Multilevel Force Balanced Downhole Drilling Tools and Methods

ABSTRACT

Various downhole drilling tools designed and manufactured at least in part on evaluating respective forces acting on respective groups and sets of cutting elements during simulated engagement with the downhole end of a wellbore and drilling from a first downhole formation into a second downhole formation. Simulating forces acting on each cutting element as the cutting element contacts a downhole formation may be used to force balance downhole drilling tools during transition drilling or non-uniform downhole drilling conditions. Multilevel force balanced downhole drilling tools may be designed using five respective simulations, cutter group level, neighbor cutter group level, cutter set level, group of N (N=3 or N=4) consecutive cutters level and all cutters level. Various cutter layout procedures and algorithms may also be used to design multilevel force balanced downhole drilling tools which may drill faster with higher lateral stability, especially during downhole transiting drilling conditions.

RELATED APPLICATIONS

This application is related to previously filed U.S. Provisional PatentApplication entitled “Fixed Cutter Drill Bits With Improved Stability,”Ser. No. 61/121,723 filed Dec. 11, 2008 (Attorney's Docket No.074263.0485) and U.S. Provisional Application entitled “InstantBalancing Fixed Cutter Drill Bits, Reamers, Core Bits and DesignMethods,” Ser. No. 61/174,769 filed May 1, 2009 (Attorney's Docket No.074263.0512).

TECHNICAL FIELD

The present disclosure is related to downhole drilling tools including,but not limited to, rotary drill bits, core bits, and reamers and moreparticularly to design, manufacture and/or selection of such downholedrilling tools based at least in part on balancing forces acting onassociated cutting elements during initial contact with the downhole endof a wellbore and/or transition drilling through a first downholeformation and into a second downhole formation.

BACKGROUND OF THE DISCLOSURE

Various types of downhole drilling tools including, but not limited to,rotary drill bits, reamers, core bits, and other downhole tools havebeen used to form wellbores in associated downhole formations. Examplesof such rotary drill bits include, but are not limited to, fixed cutterdrill bits, drag bits, PDC drill bits, and matrix drill bits associatedwith forming oil and gas wells extending through one or more downholeformations. Various techniques and procedures have been used tostabilize such downhole drilling tools and improve their drillingperformance. See for example: Brett J. F, Warren T. M. and Behr S. M.,“Bit Whirl: A new Theory of PDC bit Failure”, SPE 19571, October, 1989;Warren T. M, Brett J. F. and Sinor L. A., “Development of aWhirl-Resistant Bit”, SPE Drilling Engineering, 5 (1990) 267-274; WeaverG. E., Clayton R., “A New PDC Cutting Structure Improves BitStabilization and Extends Application into Harder Rock Types”, SPE/IADC25734, 1993; Besson A., et al, “On the Cutting Edge”, Oilfield Review,Autumn, 2000, p 36-57; and TransFormation Bits, ReedHycalog, 2004.

Prior techniques used to force balance fixed cutter rotary drill bitsand other downhole drilling tools often assume that all cutting elementsare engaged with a generally uniform downhole formation. Variouscomputer programs and computer models are available to simulate drillinga wellbore based at least in part on this assumption.

SUMMARY OF THE DISCLOSURE

In accordance with teachings of the present disclosure, rotary drillbits and other downhole drilling tools may be designed and manufacturedwith various characteristics and features including, but not limited to,cutting elements disposed at selected locations to provide substantiallyuniform force balancing during initial contact with the downhole end ofa wellbore and/or transition drilling through a first downhole formationand into an adjacent second downhole formation. Respective forces actingon each cutting element may be evaluated as a function of drillingdistance as the respective cutting element engages the end of a wellboreor as each cutting element engages a second downhole formation afterdrilling through an adjacent first downhole formation. Such drill bitsand other downhole drilling tools may sometimes be described as“multilevel force balanced”.

Teachings of the present disclosure may be used to optimize the designof various features of a rotary drill bit and other downhole drillingtools including, but not limited to, the number of blades, dimensionsand configurations of each blade, configuration and dimensions ofcutting elements, the number, location, orientation and type of cuttingelements disposed on each blade and any other feature of an associatedcutting structure. Such rotary drill bits and other downhole tools maybe designed and manufactured in accordance with teachings of the presentdisclosure with multilevel force balancing during transition drilling.

Multilevel force balanced rotary drill bits and other downhole drillingtools incorporating teachings of the present disclosure may besatisfactorily used to form a wellbore extending through multipledownhole formations in less time and with greater stability as comparedwith rotary drill bits and other downhole drilling tools designed based,at least in part, on assuming that all associated cutting elements areengaged with a generally uniform downhole formation. Vibration and/orforce imbalances associated with initial contact with the downhole endof a wellbore, transition drilling from a first downhole formation layerinto a second downhole formation layer or drilling through other typesof non-uniform downhole formations may be substantially reduced oreliminated by use of multilevel force balanced downhole drilling toolsincorporating teachings of the present disclosure.

Downhole drilling tools including, but not limited to, fixed cutterrotary drill bits, core bits and reamers may be designed andmanufactured in accordance with teachings of the present disclosure withassociated cutting elements disposed at selected locations to balanceforces acting on such downhole drilling tools during initial contactwith the downhole end of a wellbore or while drilling from a firstdownhole formation into a second downhole formation.

Teachings of the present disclosure provide rotary drill bits and otherdownhole drilling tools which may be force balanced for many non-uniformdownhole drilling conditions as compared with prior rotary drill bitsand other downhole drilling tools designed based on only one level orone condition of force balancing which assumes that all cutting elementsare engaged with a generally uniform downhole formation. Fixed cutterdrill bits and other downhole drilling tools which are designed andmanufactured based, at least in part, on force balancing techniqueswhich assume that all cutting elements are engaged with the same,generally uniform downhole formation may not be force balanced duringmany common, non-uniform downhole drilling conditions such as, but notlimited to, initial contact with the end of wellbore or drilling from afirst downhole formation into a second, harder downhole formation.

For some embodiments fixed cutter rotary drill bits and other downholedrilling tools may be designed and manufactured based on simulations ofnon-uniform downhole drilling. Such simulations may include assigningassociated cutting elements to respective “cutter groups” such as twocutter groups or pair cutter groups, three cutter groups, four cuttergroups, five cutter groups, etc. The cutting elements in each cuttergroup may be force balanced (sometimes referred to as “level one forcebalancing”) in accordance with teachings of the present disclosure.

The cutting elements in each neighbor cutter group may also be forcedbalanced (sometimes referred to as “level two force balancing”) inaccordance with teachings of the present disclosure.

Cutting elements disposed on exterior portions of the associated rotarydrill bit or other downhole drilling tool may then be divided intorespective cutter sets. Each cutter set should include at least twoforce balanced cutter groups. The cutting elements in each cutter setmay also be force balanced (sometimes referred to as “level three forcebalancing”) in accordance with teachings of the present disclosure.

Neighbor cutting elements disposed on an associated bit face profile orcutting face profile may be divided into respective groups of eitherthree or four cutting elements per group. The cutting elements in eachneighbor cutter group may be force balanced (sometimes referred to as“level four force balancing”) in accordance with teachings of thepresent disclosure. The final level or “level five force balancing” mayinclude simulating forces acting on all cutting elements when engagedwith a generally uniform and/or a generally non-uniform downholeformation (sometimes referred to as “all cutter force level balancing”).

Force balancing may be evaluated after each level. One or more downholedrilling tool characteristics may be modified and simulations repeatedto optimize downhole drilling tool characteristics such as size, type,number and location of associated cutting elements and othercharacteristics of fixed cutter rotary drill bits or other downholedrilling tools to substantially reduce or eliminate imbalance forcesduring transition drilling or non-uniform downhole drilling. Variationsin forces acting on each cutting element and resulting imbalance forcesversus depth of penetration of an associated downhole drilling tool maybe used to design associated cutting elements, cutting structures andother downhole tool characteristics.

Further aspects of the present disclosure may include one or morealgorithms or procedures for laying out or selecting locations forinstalling respective cutting elements on exterior portions of a rotarydrill bit or other downhole drilling tool. A multilevel force balancedfixed cutter rotary drill bit, core bit, reamer or other downholedrilling tool may have increased stability and a higher rate ofpenetration for the same general downhole drilling conditions (weight onbit, rate of rotation, etc.) as compared with more traditional forcedbalanced drilling tools especially during transition drilling between afirst formation layer and a second formation layer.

Many prior fixed cutter rotary drill bits and other downhole drillingtools may be described as force balanced for only one level or one setof downhole drilling conditions. Currently available computer models anddesign techniques generally use only one level of force balancing toimprove bit lateral stability by minimizing lateral imbalance forcesincluding drag lateral imbalance forces and radial lateral forces. Someprior force balancing techniques may also include balancing axial bitbending moments. The one level or one set of downhole drillingconditions typically includes all cutting elements engaged with agenerally uniform downhole formation and does not generally considertransient forces during non-uniform downhole drilling conditions.Simulations conducted in accordance with teachings of the presentdisclosure indicate that one level force balanced conditions may oftenbe violated during transition drilling through downhole formations withnon-uniform properties.

Force balanced conditions of traditional one level force balanced PDCbits may be significantly violated during initial engagement with thedownhole end of a wellbore and during transit drilling with non-uniformdownhole conditions. The maximum transient lateral imbalance force maybe over 20% of axial force and the maximum axial bending moment may beover 50% of torque during transit drilling. Simulations have shownsubstantially increased benefits from using rotary drill bits and otherdownhole drill tools which have been designed and manufactured based onmultilevel force balancing techniques incorporating teachings of thepresent disclosure as compared to prior fixed cutter rotary drill bitsand other downhole drilling tools with only one level of forcebalancing.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete and thorough understanding of the various embodimentsand advantages thereof may be acquired by referring to the followingdescription taken in conjunction with the accompanying drawings, inwhich like reference numbers indicate like features, and wherein:

FIG. 1A is a schematic drawing in section and in elevation with portionsbroken away showing examples of wellbores which may be formed indownhole formations by a rotary drill bit or other downhole drillingtools incorporating teachings of the present disclosure;

FIG. 1B is a schematic drawing in section and in elevation with portionsbroken away showing the rotary drill bit of FIG. 1A drilling a wellborethrough a first downhole formation and into an adjacent second downholeformation;

FIG. 1C is a schematic drawing in elevation with portions broken awayshowing one example of possible effects from bit imbalance forcesapplied to a rotary drill bit which has not been multilevel forcebalanced in accordance with teachings of the present disclosure;

FIG. 1D is a process diagram showing one example of techniques orprocedures which may be used to design various downhole drilling toolsin accordance with teachings of the present disclosure;

FIG. 2A is a schematic drawing showing an isometric view of a fixedcutter drill bit oriented in a generally downhole direction which mayincorporate teachings of the present disclosure;

FIG. 2B is a schematic drawing showing an isometric view of a fixedcutter drill bit incorporating teachings of the present disclosure andoriented upwardly in a manner often used to model or design fixed cutterdrill bits;

FIG. 3 is a schematic drawing in elevation showing one example of a corebit incorporating teachings of the present disclosure;

FIG. 4 is a schematic drawing in elevation and in section with portionsbroken away showing various downhole drilling tools including, but notlimited to, a reamer or hole opener and a fixed cutter drill bitincorporating teachings of the present disclosure;

FIGS. 5A and 5B are schematic drawings showing examples of forces whichmay act on respective cutting elements while forming a wellbore usingfixed cutter rotary drill bit;

FIGS. 5C and 5D are schematic drawings showing a summation of forces orresulting forces such as bit axial force, torque on bit (TOB), moment onbit (MB) and bit lateral force acting on the rotary drill bit of FIGS.5A and 5B;

FIGS. 6A-6D are schematic drawings showing the downhole end of a rotarydrill bit and examples of prior techniques for placing cutting elementson exterior portions of associated blades;

FIG. 7 is a schematic drawing showing one example of a prior art fixedcutter drill bit forming a wellbore and a chart showing imbalance forcesversus drilling depth associated with transition drilling or non-uniformdownhole drilling conditions;

FIGS. 8A-8D are graphical representations of imbalance forces associatedwith transition drilling such as shown in FIG. 7;

FIGS. 9A, 9B and 9C are schematic drawings showing examples ofnon-uniform downhole drilling conditions or transition drillingconditions which may effect bit imbalance forces acting on an associatedrotary drill bit;

FIGS. 10A and 10B are schematic drawings showing various techniques toselect a pair group of cutters which may be used to multilevel forcebalance a downhole drilling tool in accordance with teachings of thepresent disclosure;

FIGS. 10C and 10D are schematic drawings showing various techniques toselect a three cutter group which may be used to multilevel forcebalance a downhole drilling tool in accordance with teachings of thepresent disclosure;

FIGS. 10E and 10F are schematic drawings showing various techniques toselect a four cutter group which may be used to multilevel force balancea downhole drilling tool in accordance with teachings of the presentdisclosure;

FIGS. 10G and 10H are schematic drawings showing various techniques toselect a five cutter group which may be used to multilevel force balancea downhole drilling tool in accordance with teachings of the presentdisclosure;

FIGS. 11A and 11B are schematic drawings showing various techniques toselect or layout locations for installing respective cutting elements ina cutter set used to multilevel force balance a downhole drilling toolin accordance with teachings of the present disclosure;

FIGS. 12A-12D are schematic drawings showing various techniques toselect or layout locations for installing respective cutting elements ina cutter set which may be used to multilevel force balance a downholedrilling tool (four respective cutter sets) in accordance with teachingsof the present disclosure;

FIGS. 13A and 13B are schematic drawings showing one example of an outercutter set of multilevel force balanced cutting elements disposed on afixed cutter rotary drill bit incorporating teachings of the presentdisclosure;

FIGS. 13C and 13D are schematic drawing showing one example of an innercutter set of multilevel force balanced cutting elements disposed on afixed cutter rotary drill bit incorporating teachings of the presentdisclosure;

FIG. 14 is a schematic drawing showing one example of prior proceduresto select or lay out locations for installing cutting elements on thecutting face of a downhole drilling tool starting from an associatedrotational axis;

FIGS. 15A and 15B are schematic drawings showing examples of selectingor laying out locations for installing cutting elements relative to anose point on an associated composite cutting face profile in accordancewith teachings of the present disclosure;

FIGS. 16A-16D are schematic drawings showing various examples forselecting locations to install cutting elements on exterior portions ofa downhole drilling tool having ten blades using blade groups and cuttersets in accordance with teachings of the present disclosure;

FIG. 17 is a schematic drawing showing one example of techniques toselect locations for installing cutting elements on exterior portions ofa downhole drilling tool having nine blades using three blade groups inaccordance with teachings of the present disclosure;

FIG. 18 is a schematic drawing showing one example of techniques toselect locations for installing cutting elements on exterior portions ofa downhole drilling tool having nine blades using four blade groups inaccordance with teachings of the present disclosure;

FIGS. 19A and 19B are schematic drawings showing one example of priortechniques for selecting locations for installing cutting element on afixed cutter rotary drill bit relative to an associated bit rotationalaxis;

FIGS. 20A-20G are graphs showing imbalanced force levels duringtransition drilling which may result from installing cutting element onthe drill bit shown in FIGS. 19A and 19B and using prior art techniquesto force balance such cutting elements;

FIGS. 21A and 21B are schematic drawings showing one example of a fixedcutter rotary drill bit with cutting element disposed thereon inaccordance with teachings of the present disclosure;

FIGS. 22A-22D are graphs showing reduced imbalance forces duringtransition drilling resulting from multilevel force balancing andinstalling cutting elements on the drill bit shown in FIGS. 21A and 21Bin accordance with teachings of the present disclosure;

FIGS. 22E and 22F are graphs showing lateral forces and phase angles ofeach individual cutter of the drill bit shown in FIGS. 21A and 21B inaccordance with teachings of the present disclosure;

FIG. 22G is a graph showing level one force balancing of the drill bitshown in FIGS. 21A and 21B in accordance with teachings of the presentdisclosure;

FIG. 22H is a graph showing level two force balancing of the drill bitshown in FIGS. 21A and 21B in accordance with teachings of the presentdisclosure;

FIG. 22I is a graph showing level three force balancing of the drill bitshown in FIGS. 21A and 21B in accordance with teachings of the presentdisclosure;

FIGS. 22J-1 and 22J-2 are graphs showing level four force balancing ofthe drill bit shown in FIGS. 21A and 21B in accordance with teachings ofthe present disclosure;

FIGS. 23A and 23B are process diagrams showing one example of methods oftechniques which may be used to force balance a downhole drilling tooland to install cutting elements on exterior portions of the downholedrilling tool in accordance with teachings of the present disclosure;

FIG. 24A is a schematic drawing showing an end view of a fixed cutterrotary drill bit incorporating teachings of the present disclosure;

FIG. 24B is a schematic drawing showing portions of a bit profileresulting from placing cutting elements proximate the nose portions ofthe drill bit in FIG. 24A in accordance with teachings of the presentdisclosure;

FIGS. 25A and 25B are tables showing examples of matching major blades,cutter groups, blade groups and cutter sets for use in multilevel forcebalancing of fixed cutter rotary drill bits or other downhole drillingtools in accordance with teachings of the present disclosure; and

FIG. 26 is a table showing preferred matches of major blades, cuttergroups, blade groups and cutter sets during design of multilevel forcebalance fixed cutter rotary drill bits or other downhole drilling toolsin accordance with teachings of the present disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

Preferred embodiments and various advantages of the disclosure may beunderstood by reference to FIGS. 1A-26 wherein like numbers refer tosame and like parts.

The terms “bottom hole assembly” or “BHA” may be used in thisapplication to describe various components and assemblies disposedproximate one or more downhole drilling tools disposed proximate thedownhole end of a drill string. Examples of components and assemblies(not expressly shown) which may be included in various cuttingstructures such as in a bottom hole assembly or BHA include, but are notlimited to, a bent sub, a downhole drilling motor, sleeves, stabilizersand downhole instruments. A bottom hole assembly may also includevarious types of well logging tools (not expressly shown) and otherdownhole tools associated with directional drilling of a wellbore.Examples of such logging tools and/or directional drilling tools mayinclude, but are not limited to, acoustic, neutron, gamma ray, density,photoelectric, nuclear magnetic resonance, rotary steering tools and/orany other commercially available well tool.

The terms “cutting element” and “cutting elements” may be used in thisapplication to include, but are not limited to, various types ofcutters, compacts, buttons, and inserts satisfactory for use with a widevariety of rotary drill bits and other downhole drilling tools. Impactarrestors, gage cutters, secondary cutters and/or back up cutters mayalso be included as part of the cutting structure of rotary drill bitsand other downhole drilling tools formed in accordance with teachings ofthe present disclosure. Polycrystalline diamond compacts (PDC) andtungsten carbide inserts are often used to form cutting elements forrotary drill bits, reamers, core bits and other downhole drilling tools.Various types of other hard, abrasive materials may also besatisfactorily used to form cutting elements for rotary drill bits.

The terms “cutting face”, “cutting face profile” and “composite cuttingface profile” describe various components, segments or portions of adownhole drilling tool operable to engage and remove formation materialsto form an associated wellbore. The cutting face of a downhole drillingtool may include various cutting structures such as one or more bladeswith respective cutting elements disposed on exterior portions of eachblade. A cutting face may also include impact arrestors, back upcutters, gage cutters and/or an associated gage pad. The cutting face ofa fixed cutter rotary drill bit may also be referred to as a “bit face”.

The terms “cutting face profile” and “composite cutting face profile”may also describe various cutting structures including blades andassociated cutting elements projected onto a radial plane extendinggenerally parallel with an associated rotational axis. The cutting faceprofile of a fixed cutter rotary drill bit and/or a core bit may also bereferred to as a “bit face profile” or “composite bit face profile”.

The term “cutting structure” may be used in this application to includevarious combinations and arrangements of cutting elements, impactarrestors, backup cutters and/or gage cutters formed on exteriorportions of a rotary drill bit or other downhole drill tools. Somerotary drill bits and other downhole drilling tools may include one ormore blades extending from an associated bit body with respectivecutting elements disposed of each blade. Such blades may sometimes bereferred to as “cutter blades”.

The terms “downhole drilling tool” or “downhole drilling tools” mayinclude rotary drill bits, matrix drill bits, drag bits, reamers, nearbit reamers, hole openers, core bits and other downhole tools havingcutting elements and/or cutting structures operable to remove downholeformation materials while drilling a wellbore.

The terms “downhole” and “uphole” may be used in this application todescribe the location of various components of a downhole drilling toolrelative to portions of the downhole drilling tool which engage thebottom or end of a wellbore to remove adjacent formation materials. Forexample an “uphole” component may be located closer to an associateddrill string or bottom hole assembly as compared to a “downhole”component which may be located closer to the bottom or end of anassociated wellbore.

The terms “force balanced” and “force balancing” may be used in thisapplication to describe various methods, procedures and techniquesassociated with designing rotary drill bits and other downhole drillingtools. Fixed cutter rotary drill bits have often been designed to beforce balanced based in part on computer models or programs which assumethat all associated cutting elements are engaged with a generallyuniform downhole formation while forming a wellbore. This traditionaltype of force balancing generally provides only one level of forcebalancing. As a result rotary drills and other downhole drilling toolsmay experience large imbalance forces during transition drilling whenall associated cutting elements are not engaged with a generally uniformdownhole formation.

Prior force balancing techniques which use only one level of forcebalancing (such as all cutting elements engaged with a generally uniformdownhole formation) may not adequately describe forces acting on arotary drill bit or other downhole drilling tools during initial contactwith the downhole end of a wellbore, during transition drilling betweena first downhole formation and a second downhole formation and any otherdownhole drilling conditions which do not include all cutting elementsengaged with a generally uniform downhole formation. Rotary drill bitsdesigned at least in part based on this assumption may experiencesignificant imbalance forces during non-uniform downhole drillingconditions.

The term “gage pad” as used in this application may include a gage, gagesegment, gage portion or any other portion of a rotary drill bit. Gagepads may be used to help define or establish a nominal inside diameterof a wellbore formed by an associated rotary drill bit. The layout oflocations for installing cutting elements on exterior portions of ablade may terminate proximate an associated gage pad.

The terms “multilevel force balanced” and “multilevel force balancing”may include, but are not limited to, various methods, techniques andprocedures to simulate or evaluate imbalance forces acting on downholedrilling tools while forming a wellbore with non-uniform downholedrilling conditions. Multilevel force balancing generally includes theuse of respective cutter groups and cutter sets and is not limited to asingle set of all cutting elements of a downhole drilling tool engagedwith a generally uniform downhole formation. Multilevel force balancingmay also include evaluating bit imbalance forces as a function ofdrilling depth.

A rotary drill bit or other downhole drilling tool may be designed basedat least in part on simulations using multilevel force balancingtechniques to limit:

(a) maximum transient lateral imbalance force to less than approximately8% (and often preferably less than approximately 6%) of associatedtransient axial force;

(b) lateral imbalance force, when all cutters are engaged with a generaluniform downhole formation, to less than approximately 4% of bit actualforce;

(c) maximum transient radial lateral imbalance forces to less thanapproximately 6% (preferably less than approximately 4%) of associatedtransient axial force;

(d) radial lateral imbalance force, when all cutters are engaged with agenerally uniform downhole formation, to less than approximately 2.5% ofassociated bit axial force;

(e) maximum transient drag lateral imbalance force to less thanapproximately 6% (and often preferably less than approximately 4%) ofassociated transient axial force;

(f) drag lateral imbalance force while all cutters are engaged with ageneral uniform downhole formation to less than approximately 2.5% ofassociated bit axial force;

(g) maximum axial movement to less than approximately 15% of associatedtransient torque; and

(h) axial moment, when all cutters are engaged with a general uniformdownhole formation, to less than approximately 4% of associated bittorque.

Traditional, prior art force balancing techniques which use only onelevel such as all cutting elements engaged with a generally uniformdownhole formation often only meet a limited number of the aboveconditions such as items (b), (d), (f) and (h).

The terms “multilevel force balance” and “multilevel force balancing”may also include, but are not limited to, various levels of forcebalancing such as level one through level five.

First level or level one may include balancing forces acting on allcutting elements in each respective cutter group in accordance withteachings of the present disclosure. Each cutter group may have 2, 3, 4or 5 cutters. See FIGS. 10A-10H. When performing level one forcebalancing, the cutters in each cutter group may be in a uniformformation. For some applications multilevel force balancing may beconducted with respective groups of more than five neighbor cutters.

Second level or level two force balancing may include balancing forcesacting on each cutting element in any two neighbor cutter groups on anassociated composite cutting face profile. When performing level twoforce balancing, the cutters in the two groups may be in a uniformformation. Imbalance forces resulting from any two neighbor cuttergroups on an associated composite cutting face profile may besubstantially minimized or eliminated (balanced). See FIGS. 11A, 11B and12A-12D.

Third level or level three force balancing may include balancing forcesacting on all cutting elements in each cutter set. The number of cutterswithin each cutter set may equal the number of blades on an associateddownhole drilling tool. A cutter set may include at least two forcebalanced neighbor cutter groups. When performing level three forcebalancing, the cutters in the set may be in a uniform formation.Imbalance forces resulting from all cutters in each cutter set areminimized or eliminated (balanced). See FIGS. 12A-12D, 16A-16D, 17, and18. Depending on the number of primary blades and the starts ofsecondary blades, one or more cutter sets may be incomplete due to minorblades. For example, the first cutter set listed in FIG. 22I has onlytwo cutters (1,2) on blades (3,7), respectively.

Fourth level or level four force balancing may include balancing forcesacting on any group of N (N=3 or N=4) consecutive cutters on anassociated composite cutting face profile. When performing level fourforce balancing, the cutters may be in a uniform formation. Respectiveimbalance forces resulting from each group of N (N=3 or N=4) neighborcutters may be substantially minimized or eliminated (e.g., balanced).See FIGS. 22J-1 and 22J-2. The number of N (N=3 or N=4) depends on thenumber of blades and the cutter set used to layout the cutters. See FIG.26.

Fifth level or level five force balancing may include balancing forcesacting on all cutting elements of a composite bit face profile based onsimulating all cutting elements engaged with a generally uniform and/ora generally non-uniform downhole formation. When a generally uniformformation is drilled, level five force balancing may be similar to priorone level force balancing techniques. Respective imbalance forcesresulting from each group of either three or four neighbor cutters maybe substantially minimized or eliminated (balanced). See FIG. 22H. Thenumber of cutting elements (3 or 4) in each neighbor cutter groupdepends on the number of blades and the number of cutter sets.

For some downhole drilling tools, only levels one, two, three and fiveforce balancing may be conducted. However, level four force balancingmay be preferred for many downhole drilling tools. Levels one, two,three and five force balancing may be accomplished using cutter layoutalgorithms as shown in FIGS. 25A, 25B and 26 starting from the nosepoint of an associated composite cutting face profile.

The term “neighbor cutters” may be used in this application to includecutting elements disposed immediately adjacent to each other (e.g.,consecutively numbered) on an associated cutting face profile or bitface profile with less than 100% overlap between respective cuttingsurfaces of the immediately adjacent cutting elements.

The term “force balanced cutter group” includes, but is not limited to,that the magnitude of the imbalance forces associated with the cuttersin the group is smaller than that associated with each individual cutterin the same group.

The term “force balanced two neighbor cutter groups” includes, but isnot limited to, that the magnitude of the imbalance forces associatedwith the two neighbor cutter groups is smaller than that associated witheach individual cutter in the same two neighbor cutter groups.

The term “force balanced cutter set” includes, but is not limited to,that the magnitude of the imbalance forces associated with the cuttersin the set is smaller than that associated with each individual cutterin the same set.

The term “force balanced N (N=3 or N=4) consecutive neighbor cutters”includes, but is not limited to, that the magnitude of the imbalanceforces associated with N consecutive neighbor cutters is smaller thanthe maximum imbalance forces associated with each cutter of Nconsecutive cutters.

The term “rotary drill bit” may be used in this application to includevarious types of fixed cutter drill bits, fixed cutter rotary drillbits, PDC bits, drag bits, matrix drill bits, steel body drill bits andcore bits operable to form at least portions of a wellbore in a downholeformation. Rotary drill bits and associated components formed inaccordance with teachings of the present disclosure may have manydifferent designs, configurations and/or dimensions.

The terms “reamer” and “reamers” may be used in the application todescribe various downhole drilling tools including, but not limited to,near bit reamers, winged reamers and hole openers.

Various computer programs and computer models may be used to designcutting elements, blades, cutting structure and/or associated downholedrilling tools in accordance with teachings of the present disclosure.Examples of such programs and models which may be used to design andevaluate performance of downhole drilling tools incorporating teachingsof the present disclosure are shown in copending U.S. patentapplications entitled “Methods and Systems for Designing and/orSelecting Drilling Equipment Using Predictions of Rotary Drill BitWalk,” application Ser. No. 11/462,898, filing date Aug. 7, 2006 (nowU.S. Pat. No. 7,778,777); copending U.S. patent application entitled“Methods and Systems of Rotary Drill Bit Steerability Prediction, RotaryDrill Bit Design and Operation,” application Ser. No. 11/462,918, filedAug. 7, 2006 (now U.S. Pat. No. 7,729,895) and copending U. S. patentapplication entitled “Methods and Systems for Design and/or Selection ofDrilling Equipment Based on Wellbore Simulations,” application Ser. No.11/462,929, filing date Aug. 7, 2006 (now U.S. Pat. No. 7,827,014).

Various aspects of the present disclosure may be described with respectto downhole drilling tools such as shown in FIGS. 1A-26. Examples ofsuch downhole drilling tools may include, but are not limited to, rotarydrill bits 100, 100 a, 100 b and 100 c, core bit 500 and reamer 600.Rotary drill bit 90 and associated cutting structure is one example ofprior rotary drill bits and other downhole drilling tools which have notbeen force balanced in accordance with teachings of the presentdisclosure.

Rotary drill bits 100, 100 a, 100 b and 100 c, core bit 500 and reamer600 may include three or more blades with respective cutting elementsdisposed at selected locations on associated blades in accordance withteachings of the present disclosure. The teachings of the presentdisclosure are not limited to rotary drill bits 500 and/or 100 a, 100 band 100 c, core bit 500 or reamer 600.

FIG. 1A shows examples of wellbores or bore holes which may be formed bydownhole drilling tools incorporating teachings of the presentdisclosure. Rotary drill bit 100 may be designed and manufactured usingmultilevel force balancing techniques in accordance with teachings ofthe present disclosure to substantially reduce and/or minimize imbalanceforces which may result from contact between rotary drill bit 100 anddownhole end 36 of wellbore 30 or downhole end 36 a of wellbore 30 a.

Various aspects of the present disclosure may be described with respectto drilling rig 20, drill string 24 and attached rotary drill bit 100.Cutting elements may be disposed at selected locations on exteriorportions of blades 131-136 to substantially reduce and/or eliminateimbalance forces acting on rotary drill bit 100 during non-uniformdownhole drilling conditions or transition drilling conditions.

Bit imbalance forces associated with non-uniform downhole drillingconditions are discussed in more detail with respect to rotary drill bit90 in FIGS. 7, 8A-8D and rotary drill bit 90 a in FIGS. 19A-20G. Bitimbalance forces may cause vibration of drill string 24 when rotarydrill bit 100 initially contacts end 36 of wellbore 30 or end 36 a ofhorizontal wellbore 30 a. See FIG. 1A. Such vibration may extend fromrotary drill bit 100 throughout the length of drill string 24. See FIG.1C. Imbalance forces acting on a downhole drilling tool may also resultduring transition drilling from a first generally soft formation layerinto a second, generally harder downhole formation layer. See, forexample, FIGS. 1B and 7. Imbalance forces acting on a downhole drillingtool may also result from drilling from a first downhole formation intoa second downhole formation where the second downhole formation may betilted at an angle other than normal to a wellbore formed by a downholedrilling tool. See, for example, FIGS. 9A, 9B and 9C.

Wellbores 30 and/or 30 a may often extend through one or more differenttypes of downhole formation materials or formation layers. As shown inFIG. 1B, rotary drill bit 100 may be used to extend wellbore 30 throughfirst formation layer 41 and into second formation layer 42. For someapplications, first formation layer 41 may have a compressive strengthor hardness less than the compressive strength or hardness of secondformation layer 42.

During transition drilling between first layer 41 and second harderlayer 42, significant imbalance forces may be applied to a downholedrill tool resulting in undesired vibration of an associated downholedrill string. Vibration and/or imbalance forces associated with initialcontact with a downhole formation at the end of a wellbore, transitiondrilling from a first formation layer into a second formation layer andother non-uniform downhole drilling conditions will be discussed in moredetail.

Various types of drilling equipment such as a rotary table, mud pumpsand mud tanks (not expressly shown) may be located at well surface orwell site 22. Drilling rig may have various characteristics and featuresassociated with a “land drilling rig”. However, downhole drilling toolsincorporating teachings of the present disclosure may be satisfactorilyused with drilling equipment located on offshore platforms, drill ships,semi-submersibles and drilling barges (not expressly shown).

Bottom hole assembly 26 may be formed from a wide variety of components.For example, components 26 a, 26 b and 26 c may be selected from thegroup consisting of, but not limited to, drill collars, rotary steeringtools, directional drilling tools and/or downhole drilling motors. Thenumber of components such as drill collars and different types ofcomponents included in a bottom hole assembly will depend uponanticipated downhole drilling conditions and the type of wellbore whichwill be formed by drill string 24 and rotary drill bit 100.

Drill string 24 and rotary drill bit 100 may be used to form a widevariety of wellbores and/or bore holes such as generally verticalwellbore 30 and/or generally horizontal wellbore 30 a as shown in FIG.1A. Various directional drilling techniques and associated components ofbottomhole assembly 26 may be used to form horizontal wellbore 30 a. Forexample, lateral forces may be applied to rotary drill bit 100 proximatekickoff location 37 to form horizontal wellbore 30 a extending fromgenerally vertical wellbore 30.

Excessive amounts of vibration or imbalance forces applied to a drillstring while forming a directional wellbore may cause significantproblems with steering drill string and/or damage one or more downholecomponents. Such vibration may be particularly undesirable duringformation of directional wellbore 30 a. Designing and manufacturingrotary drill bit 100 and/or other downhole drilling tools usingmultilevel force balancing techniques incorporating teachings of thepresent disclosure may substantially enhance stability and steerabilityof rotary drill bit 100 and other downhole drilling tools.

Wellbore 30 defined in part by casing string 32 may extend from wellsurface 22 to a selected downhole location. Portions of wellbore 30 asshown in FIG. 1A which do not include casing 32 may be described as“open hole”. Various types of drilling fluid may be pumped from wellsurface 22 through drill string 24 to attached rotary drill bit 100.Such drilling fluids may be directed to flow from drill string 24 torespective nozzles 156 provided in rotary drill bit 100. See for examplenozzles 156 in FIGS. 2A and 2B. The drilling fluid may be circulatedback to well surface 22 through annulus 34 defined in part by outsidediameter 25 of drill string 24 and inside diameter 31 of wellbore 30.Inside diameter 31 may also be referred to as the “sidewall” of wellbore30. Annulus 34 may also be defined by outside diameter 25 of drillstring 24 and inside diameter 33 of casing string 32.

Rate of penetration (ROP) of a rotary drill bit is often a function ofboth weight on bit (WOB) and revolutions per minute (RPM). Drill string24 may apply weight on drill bit 100 and also rotate drill bit 100 toform wellbore 30. For some applications a downhole motor (not expresslyshown) may be provided as part of bottom hole assembly 26 to also rotaterotary drill bit 100.

FIG. 1B shows rotary drill bit 100 forming wellbore 30 through firstformation layer 41 into second formation layer 42. Formation layer 41may be described as “softer” or “less hard” when compared with downholeformation layer 42. Various details associated with designing andmanufacturing rotary drill bit 100 using multilevel force balancingtechniques incorporating teachings of the present disclosure will befurther discussed with respect to FIGS. 21A, 21B and 22A-22J.

Exterior portions of rotary drill bit 100 which contact adjacentportions of a downhole formation may be described as a “bit face”. Bitface 126 of rotary drill bit 100 may include generally cone shapedsegment or inner zone 160, nose segment or nose zone 170 and shoulder orouter segment 180 defined in part by respective portions of associatedblades 131-138.

A plurality of cone cutters 60 c may be disposed on cone or innersegment 160. A plurality of nose cutters 60 n may be disposed on nosesegment 170. A plurality of shoulder cutters 60s may be disposed onshoulder or outer segment 180 in accordance with teachings of thepresent disclosure. See FIGS. 21A and 21B for additional details. Conecutters 60 c may also be described as “inner cutters”. Shoulder cutter60s may also be described as “outer cutters”.

Generally convex or outwardly curved nose segment or nose zone 170 maybe formed on exterior portions of each blade 131-138 adjacent to andextending from cone shaped segment 160. Respective shoulder segments 180may be formed on exterior portions of each blade 131-138 extending fromrespective nose segments 170. Each shoulder segment 180 may terminateproximate a respective gage cutter or gage pad on each blade 131-138such as gage cutters 60 g in FIG. 2A and gage pad 150 in FIGS. 1B and1C. Exterior portions of blades 131-138 and cutting elements 60 may beprojected onto a radial plane to form a bit face profile or a compositebit face profile. Composite bit face profile 110 associated with rotarydrill bit 100 are shown in FIGS. 5A, 5C, 9A-9C and 21B.

Cutting elements or nose cutters 60 n may be disposed at selectedlocations on nose segments 170 of respective blades 131-138 inaccordance with teachings of the present disclosure to initially contacta downhole formation and avoid creating undesired imbalance force actingon drill bit 100. In some embodiments, two or more cutting elements maybe optimally located on respective blades to make approximatelysimultaneous contact with the downhole end of a wellbore andsubstantially reduce and/or eliminate imbalance forces and/or vibrationsacting on an associated drill bit and drill string.

Various features of the present disclosure may be defined with respectto rotary drill bits 90 and a 100. The size, configuration and otherdesign parameters associated with rotary drill bits 90 and 100 may bethe same except for locations selected or laid out for installingrespective cutting elements on exterior portions of associated blades.Blades 131-138 of rotary drill bit 100 may have the same configurationand dimensions as blades 91-98 of rotary drill bit 90.

Rotary drill bit 90 may be described as a prior art drill bit becauselocations selected to install cutting elements on blades 91-98 are basedon:

only one level of force balancing assuming all cutters are engaged witha generally uniform downhole formation; and

cutter layout starts from a first portion on a primary blade closelyadjacent to an associated bit rotational axis.

As shown in FIG. 1C, vibration and/or bit imbalance forces may betransmitted from rotary drill bit to drill string 24. Undesirablechanges in inside diameter 31 of wellbore 30 and/or excessive wear onrotary drill bit 90 and/or components of drill string 24 may occur. Suchvibration may even damage equipment located at well surface 22. Dottedlines 25 a, 25 b and 25 c show examples of vibration which may occurbased in part on the magnitude of imbalance forces applied to rotarydrill bit 90. See FIGS. 7 and 8A-8D.

Since rotary drill bit 90 and bottom hole assembly are generallydisposed in a wellbore that limits lateral movement, the potential fordamage to rotary drill bit 90 and/or components of bottomhole assembly26 may significantly increase as imbalance forces applied to rotarydrill bit 90 increase. Fixed cutter rotary drill bit 90 may remaingenerally force balanced during drilling conditions such as all cuttingelements 60 engaged with generally uniform downhole formation layer 42.Various methods and techniques of the present disclosure such as shownin FIGS. 1D and 23A-23B may be used to evaluate transient imbalanceforces acting on a downhole drilling tool.

Simulations of rotary drill bits 90 and 100 or other downhole drillingtools such as core bit 500 or reamer 600 forming wellbores may use sixparameters to define or describe downhole drilling motion. Theseparameters include rotational speed in revolutions per minutes (RPM) andrate of penetration (ROP) relative to an associated rotational axis.Tilt rate relative to an x axis and a y axis extending from theassociated rotational axis may be used during simulation of directionaldrilling. See wellbore 30 a in FIG. 1A. The rate of lateral penetrationalong a x axis and the rate of lateral penetration along a y axis mayalso be used to simulate forming a wellbore in accordance with teachingsof the present disclosure. See FIGS. 1D, 23A and 23B. The x axis and yaxis may extend perpendicular from each other and from an associated bitrotational axis.

For simulation purposes, rate of penetration may remain constant andweight on bit (WOB) may vary. During actual drilling of a wellbore at afield location, weight on bit will often be maintained relativelyconstant and rate of penetration may vary accordingly depending uponvarious characteristics of associated downhole formations.

Fixed cutter rotary drill bits and other downhole drilling tools may bedesigned and manufactured at least in part based on simulations usingmultilevel balancing techniques. Such simulations may include assigningcutting elements to respective cutter groups and cutter sets evaluatingforces acting on the cutting elements in each cutter group and cutterset, and evaluating resulting imbalance forces acting on associatedrotary drill bit or other downhole drilling tool. Design features ofcutting elements in each cutter group and cutter set and/or locationsfor installing the cutting elements may be modified using iterativeprocesses such as shown in FIGS. 1D and 23A-23B to reduce or eliminateresulting bit imbalance forces.

FIG. 1D shows one example of techniques or procedures which may be usedto design fixed cutter rotary drill bits and other downhole drillingtools based at least in part on multilevel force balancing tosubstantially reduce and/or eliminate imbalance forces acting on arotary drill bit and other downhole drilling tools. Method 400 may beginat step 402 by inputting into a general purpose computer or specialpurpose computer (not expressly shown) various characteristics of adownhole drilling tool such as rotary drill bits 100, core bit 500and/or reamer 600. Examples of such downhole drilling toolcharacteristics are shown in Appendix A at the end of this WrittenDescription.

At step 404 various downhole drilling conditions may be inputted intothe general purpose computer or special purpose computer. Examples ofsuch downhole drilling conditions are shown in Appendix A. At step 406 adrilling simulation may start with initial engagement between one ormore cutters of a fixed cutter drill bit or other downhole drilling tooland a generally flat surface of a first downhole formation layer at thedownhole end of a wellbore. A standard set of drilling conditions mayinclude one hundred twenty (120) revolutions per minute (RPM), rate ofpenetration (ROP), thirty (30) feet per hour, first formation strength5,000 psi and second formation strength 18,000 psi. See for examplerotary drill bit 90 and portions of wellbore 30 in FIG. 7.

Respective forces acting on cutting elements disposed on the fixedcutter drill bit or other downhole drilling tool may be evaluated duringinitial contact between each cutting element and the first downholeformation. Respective forces acting on each cutting element may beevaluated versus depth of penetration of the rotary drill bit or otherdownhole drilling tool into the first downhole formation. The resultingforces acting on the associated rotary drill bit or other downholedrilling tool may then be calculated as a function of drilling depth atstep 410. See for example FIGS. 7, 8A-8D, 20A-20G and 22A-22J.

The drilling simulation may continue to step 412 corresponding withforming the wellbore through the first downhole formation and into asecond downhole formation. See FIG. 7. Respective forces acting on eachcutting element engaged with the first downhole formation and respectiveforces acting on each cutting element engaged with the second downholeformation may then be evaluated at step 416. Resulting forces acting onthe fixed cutter rotary drill bit or other downhole drilling tool maythen be evaluated as a function of drilling depth in step 418. See forexample FIGS. 7 and 8A-8D, 20A-20G and 22A-22J. At step 420, resultingforces acting on the fixed cutter rotary drill bit or other downholedrilling tool may be displayed as a function of drilling depth. SeeFIGS. 7 and 8A-8D, 20A-20G and 22A-22J.

If the resulting forces acting on the fixed cutter rotary drill bit orother downhole drilling tool meet design requirements for a multilevelforce balanced drilling tool at step 422, the simulation may stop. Thedownhole drill tool characteristics may then be used to design andmanufacture the fixed cutter rotary drill bit or other downhole drillingtool in accordance with teachings of the present disclosure.

If the resulting forces acting on the fixed rotary cutter drill bit orother downhole drilling tool do not meet design requirements for amultilevel forced balance drilling tool at step 422, the simulation mayproceed to step 426 and at least one downhole drilling toolcharacteristic may be modified. For example, the location, orientationand/or size of one or more cutting elements may be modified. Theconfiguration, dimensions and/or orientation of one or more bladesdisposed on exterior portions of the downhole drilling tool may bemodified.

The simulation may then return to step 402 and method 400 may berepeated. If the simulation based on the modified downhole drilling toolcharacteristics are satisfactory at step 422, the simulation may stop.If the conditions for a multilevel force balanced drilling tool are notsatisfied at step 422, further modifications may be made to at least onedownhole drilling tool characteristic at step 426 and the simulationcontinued starting at step 402 and method 400 repeated until theconditions for a multilevel forced balanced downhole drilling tool aremet at step 422.

FIGS. 2A and 2B show rotary drill bits 100 a and 100 b which may bedesigned and manufactured using multilevel force balancing techniques inaccordance with teachings of the present disclosure. Rotary drill bits100 a and 100 b have respective bit bodies 120 a and 120 b. Respectiveblades 131 a-136 a and 131 b-136 b may be disposed on exterior portionsof bit bodies 120 a and 120 b.

For some applications, bit bodies 120 a and 120 b may be formed in partfrom a respective matrix of very hard materials associated with matrixdrill bits. For other applications, bit bodies 120 a and 120 b may bemachined from various metal alloys satisfactory for use in drillingwellbores in downhole formations.

First end or uphole end 121 of each bit body 120 a and 120 b may includeshank 152 with American Petroleum Institute (API) drill pipe threads 155formed thereon. Threads 155 may be used to releasably engage respectiverotary drill bit 100 a and 100 b with bottomhole assembly 26 wherebyeach rotary drill bit 100 a and 100 b may be rotated relative to bitrotational axis 104 in response to rotation of drill string 24. Bitbreaker slots 46 may be formed on exterior portions of upper portion orshank 152 for use in engaging and disengaging each rotary drill bits 100a and 100 b with drill string 24. An enlarged bore or cavity (notexpressly shown) may extend from first end 121 through shank 152 andinto each bit body 120 a and 120 b. The enlarged cavity may be used tocommunicate drilling fluids from drill string 24 to one or more nozzles156.

Second end or downhole end 122 of each bit body 120 a and 120 b mayinclude a plurality of blades 131 a-136 a and 131 b-136 b withrespective junk slots or fluid flow paths 240 disposed therebetween.Exterior portions of blades 131 a-136 a and 131 b-136 b and respectivecutting elements 60 disposed thereon may define in part bit facedisposed on exterior portions of bit body 120 a and 120 b respectiveproximate second end 122.

Blades 131 a-136 a may extend from second end or downhole end 122towards first end or uphole end 121 of bit body 120 a at an anglerelative to exterior portions of bit body 120 and associated bitrotational axis 104. Blades 131 a-136 a may be described as having aspiral or spiraling configuration relative to associated bit rotationalaxis 104. Blades 131 b-136 b disposed on exterior portions of bit body120 b may extend from second end or downhole end 122 towards first endor uphole end 121 aligned in a generally parallel configuration withrespect to each other and associated bit rotational axis 104. See FIG.2B.

Respective cutting elements 60 may be disposed on exterior portions ofblades 131 a-136 a and 131 b-136 b in accordance with teachings of thepresent disclosure. Rotary drill bit 100 b may include a plurality ofsecondary cutters or backup cutters 60 a disposed on exterior portionsof associated blades 131 b-136 b. For some applications each cuttingelement 60 and backup cutting element 60 a may be disposed in arespective socket or pocket (not expressly shown) formed on exteriorportions of associated blade 131 a-136 a or 131 b-136 b at locationsselected in accordance with teachings of the present disclosure. Impactarrestors (not expressly shown) may also be disposed on exteriorportions of blades 131 a-136 a and/or 131 b-136 b in accordance withteachings of the present disclosure.

Fixed cutter rotary drill bits 100 and 100 a may be described as havinga “single blade” of cutting elements disposed on the leading edge ofeach blade. Fixed cutter rotary drill bits 100 b may be described ashaving “dual blades” of cutting elements disposed on exterior portionsof each blade. Many of the features of the present disclosure will bedescribed with respect to fixed cutter rotary drill bits and otherdownhole drilling tools having a “single blade” of cutting elements.However, teachings of the present disclosure may also be used with fixedcutter rotary drill bits and downhole drilling tools such as reamers andhole openers which have “dual blades” of cutting elements disposed onassociated blades. See FIGS. 2B and 4.

Cutting elements 60 and 60 a may include respective substrates (notexpressly shown) with respective layer 62 of hard cutting materialdisposed on one end of each respective substrate. Layer 62 of hardcutting material may also be referred to as “cutting layer” 62. Cuttingsurface 164 on each cutting layer 62 may engage adjacent portions of adownhole formation to form wellbore 30. Each substrate may have variousconfigurations and may be formed from tungsten carbide or othermaterials associated with forming cutting elements for rotary drillbits.

Tungsten carbides include monotungsten carbide (WC), ditungsten carbide(W₂C), macrocrystalline tungsten carbide and cemented or sinteredtungsten carbide. Some other hard materials which may be used includevarious metal alloys and cermets such as metal borides, metal carbides,metal oxides and metal nitrides. For some applications, cutting layers62 and an associated substrate may be formed from substantially the samematerials. For some applications, cutting layers 62 and an associatedsubstrate may be formed from different materials. Examples of materialsused to form cutting layers 62 may include polycrystalline diamondmaterials including synthetic polycrystalline diamonds. One or more ofcutting element features including, but not limited to, materials usedto form cutting elements 60 may be modified based on simulations usingmethod 400.

For some applications respective gage pads 150 may be disposed onexterior portions of each blade 131 a-136 a and 131 b-136 b proximaterespective second end 142. For some applications gage cutters 60 g mayalso be disposed on each blade 131 a-136 a. Additional informationconcerning gage cutters and hard cutting materials may be found in U.S.Pat. Nos. 7,083,010, 6,845,828, and 6,302,224. Additional informationconcerning impact arrestors may be found in U.S. Pat. Nos. 6,003,623,5,595,252 and 4,889,017.

Rotary drill bit 100 a as shown in FIG. 2A may be generally described ashaving three primary blades 131 a, 133 a and 135 a and three secondaryblades 132 a, 134 a and 136 a. Blades 131 a, 133 a and 135 a may bedescribed as “primary blades” because respective first ends 141 of eachblade 131 a, 133 a and 135 a may be disposed closely adjacent toassociated bit rotational axis 104. Blades 132 a, 134 a and 136 a may begenerally described as “secondary blades” because respective first ends141 may be disposed on downhole end 122 spaced from associated bitrotational axis 104.

Rotary drill bit 100 b as shown in FIG. 2B may be generally described ashaving three primary blades 131 b, 133 b and 135 b. Rotary drill bit 100b may also include four secondary blades 132 b, 134 b, 136 b and 137 b.

Blades 131 a-136 a and 131 b-137 b may be generally described as havingan arcuate configuration extending radially from associated bitrotational axis 104. The arcuate configuration of the blades 131 a-136 aand 131 b-137 b may cooperate with each other to define in partgenerally cone shaped or recessed portion 160 disposed adjacent to andextending radially outward from associated bit rotational axis 104.Recessed portion 160 may also be described as generally cone shaped.Exterior portions of blades 131-136 associated with rotary drill bit 100along with associated cutting elements 60 disposed thereon may also bedescribed as forming portions of the bit face or cutting disposed onsecond or downhole end 122.

Various configurations of blades and cutting elements may be used toform cutting structures for a rotary drill bit or other downholedrilling tool in accordance with teachings of the present disclosure.See, for example, rotary drill bits 100, 100 a and 100 b, core bit 500and reamer 600. For some applications, the layout or respectivelocations for installing each cutting element on an associated blade maystart proximate a nose point on one of the primary blades. For examplesee FIGS. 11A, 11B, 13A-13D, 14A-14C, 15 and 21A-21B.

Core bit 500 may be generally described as having bit body 520 withshank 540 extending therefrom. Core bit 500 may have a generallylongitudinal bore or passageway 508 extending from first end 501 throughcore bit 500 to second end 502. The longitudinal bore 508 may begenerally aligned and disposed consistent with associated bit rotationalaxis 104. Interior portions of longitudinal bore 508 (not expresslyshown) may be modified to retain a sample or “core” from a downholeformation therein. A plurality of blades 531-537 may be disposed onexterior portions of bit body 520. A plurality of cutting elements 60may be disposed on exterior portions of blades 531-537 in accordancewith teachings of the present disclosure. Placing cutting elements onexterior portions of respective blades 531-537 using multiforce levelbalancing techniques may substantially reduce or eliminate bit imbalanceforces and excessive vibration of the drill string.

Reamer 600 as shown in FIG. 4 may sometimes be referred to as a “holeopener”. Reamer 600 may include generally cylindrical body 620 with aplurality of retractable arms 630 may be disposed on exterior portionsthereof. Generally cylindrical body 620 may include a longitudinal boreextending therethrough (not expressly shown) to communicate drillingfluids from drill string to rotary drill bit 100. Cylindrical body 620may also include a rotational axis (not expressly shown) generallyaligned with rotational axis 104 of rotary drill bit 100 while drillingportions of a straight wellbore such as wellbore 30 shown in FIG. 1A.Various mechanisms and techniques may be satisfactorily used to extendand retract retractable arms 630 relative to generally cylindrical body620.

Respective cutting elements 60 may be disposed on each retractable arm630 at respective locations based at least in part on multilevel forcebalancing techniques incorporating teachings of the present disclosure.Retractable arms 630 may extend radially outward so that engagementbetween cutting elements 60 and adjacent portions of downhole formationmay large or increase the diameter of wellbore 30. The increaseddiameter portion is designated as 31 a in FIG. 4.

Various downhole drilling tools including, but not limited, near bitsleeve or near bit stabilizer 650 may be disposed between reamer 600 androtary drill bit 100. Stabilizer 650 may include a plurality of blades652 extending radially therefrom. Engagement between exterior portionsof blades 652 and adjacent portions of wellbore 30 may be used tomaintain desired alignment between rotary drill bit 100 and adjacentportions of bottom hole assembly 26.

FIGS. 5A and 5B are schematic drawings showing basic forces which act onrespective cutting elements 60 disposed on exterior portions of fixedcutter rotary drill bit 100. FIGS. 5C and 5D are schematic drawingsshowing resulting bit forces or reactive bit forces acting on fixedcutter rotary drill bit 100. FIGS. 5A and 5C show a composite bit faceprofile 110 associated with fixed cutter rotary drill bit 100. Compositebit face profile 110 may be generally described as a projection ofblades 131-136 and associated cutting element 60 onto a radial planeextending generally parallel with bit rotational axis 104 and bisectingbit body 120. Bit rotational axis 104 extends through the middle ofcomposite bit face profile 110 as shown in FIGS. 5A and 5B.

Three basic forces (penetration force or axial force (F_(a)), cuttingforce or drag force (F_(d)), and side force or radial force (F_(r)))generally act on each cutting element of a downhole drilling toolengaged with adjacent portions of a downhole formation. For cuttingelements 60 e and 60 f respective penetration forces or axial forces(F_(a)) are represented by arrows, 50 e and 50 f. See FIG. 5A.Respective cutting forces or drag forces (F_(d)) acting on cuttingelements 60 e and 60 f are represented by arrows 52 e and 52 f.Respective side forces or radial forces (F_(r)) acting on cuttingelements 60 e and 60 f are represented by arrows 54 e and 54 f. See FIG.5B.

Resulting bit forces or reactive bit forces acting on rotary drill bit100 include bit axial force (BF_(a)) represented by arrow 56. The bitaxial force (BF_(a)) may correspond generally with weight on bit (WOB).Resulting forces or reactive forces acting on rotary drill bit 100 alsoinclude torque on bit (TOB) represented by arrow 57 and bit moment (MB)represented by arrow 58. See FIG. 5C. Bit lateral force (BF₁)represented by arrow 59 in FIG. 5D in the summation of cutting element60 drag forces and radial forces. Reactive forces acting on bit 100correspond with the summation of respective forces (F_(a), F_(d) andF_(r)) applied to each cutting element 60 disposed on exterior portionsof fixed cutter rotary drill bit 100.

Bit lateral force (BF₁) represented by arrow 59 in FIG. 5D may befurther divided into two component vectors bit lateral drag force(BF_(d)) and bit lateral radial force (BF₁). Bit lateral drag force(BF_(d)) represents the sum of all drag forces (F_(d)) acting on allcutting elements 60 and bit lateral radial force (BL_(r)) represents thesum of all radial forces (F_(r)) acting on all cutting elements 60.

Bit moment (MB) may be divided into two vectors: bit axial moment(MB_(a)) corresponding with the sum of axial moments acting on allcutting elements 60 and bit lateral moment (MB₁) corresponding with thesum of all lateral moments acting on all cutting elements 60. Therespective axial moment associated with each cutting element 60 may bedetermined by multiplying the radius from each cutting element to bitrotational axis 104 by the respective axial force (F_(a)). For cuttingelement 60 f, the associated cutting element axial moment is equal toradius 55 multiplied by axial force (F_(a)). See FIG. 5A.

The lateral moment for each cutting element 60 is equal to therespective radial force (F_(r)) applied to each cutting elementmultiplied by a distance from each cutting element 60 to apre-determined point on bit rotational axis 104.

Forces acting on each cutting element may be a function of respectivecutting element geometry, location and orientation relative toassociated bit body 120, bit rotational axis 104, respective downholeformation properties and associated downhole drilling conditions. SeeAppendix A. For some applications each cutting element 60 may be dividedinto multiple cutlets and the bit forces summarized for each cutlet onthe associated cutting element 60. Design and manufacture of fixedcutter rotary drill bit 100 with cutting elements 60 disposed atselected locations to minimize both bit lateral forces and bit momentsbased at least in part on multilevel force balancing may result insatisfactorily managing associated bit imbalance forces.

FIGS. 6A-6D show examples of prior layout procedures or techniques usedto select locations for placing cutting elements on exterior portions ofblades disposed on an associated bit body starting from an associatedbit rotational axis and extending radially outward in the direction ofbit rotation or in a reverse direction relative to the direction of bitrotation. FIGS. 6A and 6C are schematic drawings showing downhole end orcutting face 190 a and 190 b. Portions of corresponding compositecutting face profiles 192 are shown in FIGS. 6B and 6D.

Blades 91, 93 and 95 may be described as “primary blades” becauserespective first end 141 of each blade 91, 93 and 95 is disposed closelyadjacent to bit rotational axis 104. Blades 92, 94 and 96 may bedescribed as “secondary blades” because respective first end 141 of eachblade 92, 94 and 96 is spaced radially from bit rotational axis 104.Respective second end 142 of each blade 91-96 is radially spaced frombit rotational axis 104 proximate the outside diameter of bit body 98.

For prior fixed cutter rotary drill bits such as represented by cuttingface 190 a the location for installing the first cutting element wastypically selected on the first end of a primary blade closely adjacentto the bit rotational axis. Locations selected for installing additionalcutting elements were generally selected in either the direction of bitrotation or in a reverse to bit rotation.

For cutting face 190 a in FIG. 6A, the location for installing firstcutting element 1 was selected closely adjacent to both bit rotationalaxis 104 and first end 141 of blade 91. The location for installingsecond cutting element 2 was selected at a somewhat greater radialdistance from bit rotational axis 104 as compared with cuttingelement 1. Exterior portions of blade 93 provide desired radial spacingfrom bit rotational axis 104. The difference between the radial spacingof cutting elements 1 and 2 determine the amount of overlap betweenrespective cutting surfaces of cutting elements 1 and 2 on compositecutting face profile 192. See FIG. 6B. The location for installingcutting element 3 was selected at a greater radial distance from bitrotational axis 104 to provide satisfactory overlap with cutting element2. See FIG. 6B.

For the example represented by cutting face 190 a in FIG. 6A, cuttingelement 3 may be disposed proximate exterior portions of blade 95 spacedfrom bit rotational axis 104 at a radial distance greater than theradial distance between cutting element 2 and bit rotational axis 104.Again, the difference between the radial spacing from cutting element 3and bit rotational axis 104 and the radial spacing between element 2 andbit rotational axis 104 determines the amount of overlap between cuttingsurfaces of cutting elements 2 and 3. See FIG. 6B. The remaining cuttingelements 4-15 may be disposed on exterior portions of blades 91-96continuing in a direction corresponding with the direction of rotationrelative to bit rotational axis 104. See arrow 28.

FIGS. 6C and 6D show one example for installing cutting elements 1-15 onexterior portions of associated blades 91-96 in a generally reversedirection relative to the direction of rotation shown by arrow 28. FIGS.6B and 6D show composite cutting face profiles 192 a and 192 b withsimilar cutter locations and overlaps.

FIG. 7 is a schematic drawing showing portions of wellbore 30 andvarious locations of fixed cutter rotary drill bit 90 within wellbore30. FIG. 7 also includes chart 200 showing initial engagement of drillbit 90 with a first formation layer 41 and imbalance forces associatedwith drill bit 90 contacting a second downhole formation layer 42adjacent to first downhole formation layer 41.

Graph 200 demonstrates that prior rotary drill bits with only one levelof force balancing, such as all cutting elements engaged with agenerally uniform downhole formation, may experience substantial lateralimbalance forces during initial contact with the downhole end of awellbore and/or during transition drilling from a first downholeformation into a second downhole formation. Transient imbalance forces(bit drag lateral imbalance, bit radial lateral imbalance, bit lateralimbalance and bit axial moment) are typically used with traditional onelevel force balancing techniques associated with fixed cutter rotarydrill bits and other downhole drilling tools. Design criteria used toevaluate traditional force balanced fixed cutter rotary drill bits andother downhole drilling tools may include:

bit drag lateral imbalance force less than 2.5% of total bit axialforce;

bit radial lateral imbalance force less than 2.5% of bit axial force;

bit lateral imbalance force less than 4% of bit axial force; and

bit axial moment less than 4% of bit torque.

Various computer models and computer programs such as listed in AppendixA are available to evaluate forces acting on each cutting element 60 andany bit imbalance forces.

Chart or graph 200 is also shown adjacent to the schematic drawing ofwellbore segments 30 a and 30 b and downhole formation layers 41 and 42in FIG. 7. Graph 200 shows substantial imbalance forces that may beapplied to a fixed cutter rotary drill bit when a single cutter or a fewcutters engage a downhole formation or when the rotary drill bittransits from a first downhole formation into a second downholeformation. See also FIG. 20A.

The portion of wellbore 30 designated as 30 a may have been drilled orformed prior to inserting rotary drill bit 90. Simulations wereconducted based on inserting rotary drill bit 90 and an associated drillstring through previously formed wellbore portion 30 a until the extremedownhole end of rotary drill bit 90 contacts surface 43 to drill or formwellbore segment 30 b extending through first downhole formation layer41 and into second downhole formation layer 42. Surface 43 may bedescribed as generally flat and extending substantially normal relativeto rotary drill bit 90.

Various techniques may be used to simulate drilling wellbore 30 b usingrotary drill bit 90 and an attached drill string (not expressly shown)starting with contact between the extreme downhole end of rotary drillbit 90 and surface 43 of first layer 41.

First downhole formation layer 41 may have compressive strength lessthan the compressive strength of the second downhole formation layer 42.For some simulations, first downhole formation layer 41 may have acompressive strength of approximately 5,000 psi. During the simulationthe thickness of the first downhole formation layer 41 may be greaterthan the length of rotary drill bit 90 such that all cutting elements 60may be fully engaged with first downhole formation layer 41 prior to thedownhole end or rotary drill bit 90 contacting second downhole formationlayer 42.

Second downhole formation layer 42 may have a compressive strengthgreater than the compressive strength of the first downhole formationlayer 41. For some simulations second downhole formation layer 42 mayhave a compressive strength of approximately 18,000 psi. The thicknessof the second downhole formation may be greater than the length ofrotary drill bit 90 such that all cutting elements may be fully engagedwith second downhole formation layer 42.

Some prior fixed cutter drill bits such as rotary drill bit 90 may haveonly one cutting element 60 f disposed on one blade at or nearassociated nose point 171. If single cutting element 60 f is the onlypoint of initial contact between rotary drill bit 90 and generally flatsurface 43 at the downhole end of wellbore segment 30 a, substantiallateral impact forces may be applied to rotary drill bit 90 and drillstring 24. See FIG. 1C.

As drilling depth of rotary drill bit 90 increases into first downholeformation layer 41, substantial imbalance forces may occur as additionalcutters 60 engage adjacent portions of first formation layer 41. Seepeak 201 on graph 200. Peaks 201 and 202 on graph 200 correspond withsubstantial increases in bit lateral imbalance forces as compared withbit axial force. With increasing depth of drilling or penetration intofirst formation layer 41, imbalance forces acting on fixed cutter rotarydrill bit 90 may gradually reduce. See point 203 on graph 200. Asubstantially force balanced condition may be met when all cuttingelements 60 are engaged with adjacent portions of generally uniformfirst formation layer 41.

For the example shown in FIG. 7, the ratio of bit lateral imbalanceforces relative to total bit axial force applied to rotary drill bit 90may be relatively constant at a value of approximately 2.5% asrepresented by generally flat segment 204 of graph 200. Rotary drill bit90 may be generally be described as force balance for only one level orone condition when all cutting elements are engaged with a generallyuniform downhole formation.

Peaks 201, 202, 205 and 206 are representative of the magnitude oftransient imbalance forces which may be applied to rotary drill bit 90during transition drilling through non-uniform downhole drillingconditions represented by first layer 41 and second layer 42 as shown inFIG. 7.

The one level used to force balance rotary drill bit 90 may be violatedwhen downhole end 122 of rotary drill bit 90 initially contacts seconddownhole formation layer 42. See peak 205 on graph 200. As shown bygraph 200, bit lateral imbalance forces may spike or peak if only onecutting element 60 or a relatively small number of cutting elements 60engage generally harder second formation layer 42 and the other cuttingelements 60 remain engaged with relatively softer first downholeformation layer 41.

Simulations show that lateral imbalance force applied to rotary drillbit 90 may occur at peaks 205 and 206 as the depth of drilling increaseswith additional cutting element 60 engaging harder second downholeformation layer 42. At point 207 on graph 200 all cutting elements 60disposed on exterior portions of rotary drill bit 90 may be engaged withgenerally uniform second downhole formation layer 42. Generallyhorizontal or flat segment 208 of graph 200 represents a generallyconstant, relatively low amount of bit lateral imbalance force ascompared with bit axial force applied to rotary drill bit 90.

Forces on each cutting element 60 engaged with adjacent formationmaterial may be evaluated. Forces acting on various cutter groupsselected in accordance which are engaged with the formation material mayalso be evaluated. Associated bit forces including bit lateral force,bit axial force and bit axial moment may also be calculated and graphedas a function of drilling distance.

The graphs may start from the time the associated rotary drill bit 90first touches generally flat surface 43 and/or generally flat surface44. A visual display of all bit forces as a function of drillingdistance may then be displayed. See Graph 200 in FIG. 7. Standarddefault downhole drilling conditions which in step 402 may include RPMequal to 120, rate of penetration equal to 30 ft. per hour, compressivestrength of the first downhole formation equal to 5,000 psi andcompressive strength of a second formation equal to 18,000 psi.

FIGS. 8A-8D show various imbalance forces acting on fixed cutter rotarydrill bit 90 during initial contact with the downhole end of wellbore 30a and imbalance forces associated drilling from first downhole formationlayer 41 into harder, second downhole formation layer 42.

FIG. 8A shows graph 200 of total transient bit lateral imbalance forcesas a percentage of transient bit axial force as FIG. 7. The maximumlateral imbalance force represented by peak 201 may be greater thanfifteen percent (15%) of total bit axial force.

FIG. 8B shows graph 220 of transient bit drag lateral force as apercentage of transient bit axial force versus drilling distance. Themaximum drag lateral imbalance force represented by peak 211 may begreater than 12% of total bit axial force. Peaks 212, 214 and 215correspond generally with similar peaks shown in FIG. 8A.

FIG. 8C shows graph 230 of transient bit radial lateral force as apercentage of transient bit axial force versus drilling distance. Peak231 indicates that maximum transient radial lateral force may be greaterthan 8% of total bit axial force. Again, peaks 232, 234 and 235correspond generally with peaks 202, 205 and 206 in FIG. 8A.

FIG. 8D shows graph 240 of transient bit axial moment as a percentage oftransient bit torque versus drilling distance. Peak 241 indicates thatthe maximum transient axial bending moment may be as high as 35% of bittorque during initial engagement with downhole formation layer 41. Peaks242 and 244 of graph 240 generally correspond with similar peaks shownin FIG. 8A. Graphs 220, 230 and 240 indicate that fixed cutter rotarydrill bit 90 may be described as relatively balanced when all cuttingelements are engaged with a generally uniform downhole formation. Seefor example generally flat segments 213 and 216 in FIG. 8B, generallyflat segments 233 and 236 in FIG. 8C and generally flat segments 243 and246 in FIG. 8D.

FIGS. 9A, 9B and 9C show examples of a downhole drilling tool engaging afirst, softer downhole formation and an adjacent, harder downholeformation. FIGS. 9A, 9B and 9C show examples of the “critical point” orinitial point of contact between the downhole drilling tool and downholeformation layers disposed at various angles with respect to each other.Multiforce level balancing techniques may satisfactorily determineselected locations for installing cutting elements on exterior portionsof blades on the downhole drilling tool based at lease in part onvariations in the hardness of adjacent downhole formations and/orvariations in the angle of contacting the two adjacent downholeformations.

The critical point of contact between a downhole drilling tool andrespective downhole formations may depend upon orientation of the layerswith respect to each other and with respect to the cutting face of adownhole drilling tool during engagement with the respective downholeformations. The critical point may be determined based on dip angle (updip or down dip) of a transition between a first downhole formation anda second downhole formation relative to the cutting face of the downholedrilling tool.

Simulations of contact between the cutting face of a downhole drillingtool and a first downhole formation layer and a second downholeformation layer may indicate a critical zone with respect to thecritical point. See critical zones 114, 114 a and 114 b in FIGS. 9A, 9Band 9C. The dimensions and location of each critical zone relative tothe point of initial contact may depend on various characteristics ofthe respective downhole formations and characteristics of the cuttingface profile on the downhole drilling tool.

Composite bit face profile 110 extending from bit rotational axis 104may include various segments defined relative to nose point 171 and noseaxis 172 extending therethrough. Nose axis 172 may be aligned generallyparallel with bit rotational axis 104. Nose point 171 may be defined asthe location on bit face profile 110 with maximum elevation as measuredbit rotational axis 104 (y axis) from reference line 106 (x axis). Bitface profile 110 may be divided into various segments or zones startingfrom nose point 171 and/or nose axis 172. Such segments or zones mayinclude, but are not limited to, nose segment 170 represented by adotted oval in FIGS. 9A, 9B and 9C. Inner segment 160 may extend frombit rotational axis 104 to nose segment 170. Outer segment 180 mayextend from nose segment 170 to the end of composite bit face profile110.

Cutting elements 60 disposed on composite bit face profile 110 betweennose segment 170 and bit rotational axis 104 may sometimes be referredto as the “inner cutters” or “cone cutters”. Cutting elements 60disposed on bit face profile 110 between nose segment 170 and the end ofbit face profile 110 may be described as “outer cutters” or “shouldercutters”.

In FIG. 9A, first downhole formation layer 41 and second downholeformation layer 42 are shown disposed generally parallel with each otherand extending generally perpendicular relative to associated bitrotational axis 104 and nose axis 172. For such downhole drillingactions critical point 112 or the initial point of contact between fixedcutter drill bit 100 and surface 44 on second downhole formation layer42 may correspond approximately with the location of nose point 171 oncomposite bit face profile 110. As discussed later, there may besubstantial benefits to placing one or more groups of cutting elementswithin nose segment 170 symmetrically or pseudo-symmetrically alignedwith each other relative to nose axis 172.

For downhole drilling conditions represented by FIG. 9B, first downholeformation layer 41 a and second downhole formation layer 42 a may beinclined relative to each other and with respect to bit rotational axis104. Surface 44 a disposed between first layer 41 a and second layer 42a may be generally described as having a “up dip” angle relative to bitrotational axis 104 and an associated wellbore (not expressly shown)formed by rotary drill bit 100.

For downhole drilling conditions such as represented by FIG. 9B, initialpoint of contact 112 a between rotary drill bit 100 and surface 44 a maymove radially outward from nose point 171 as measured from bitrotational axis 104. The location of critical point 112 a may depend inpart on the up dip or angle of inclination of surface 44 a relative tobit rotational axis 104 and the dimensions and configuration of blades131-138 and cutting element 60 disposed on rotary drill bit 100.

For downhole drilling conditions such as shown in FIG. 9C, firstformation 41 b and second formation 42 b may be inclined at an angledescribed as a “down dip” relative to each other and with respect to bitrotational axis 104 and an associated wellbore formed by rotary drillbit 100. As a result, critical point 112 b may move radially inward asmeasured from bit rotational axis 104.

FIGS. 10A, 10C, 10E and 10G are schematic drawings showing variouscomponents of respective bit faces or cutting faces 126 a, 126 b, 126 cand 126 d disposed on the downhole end of a fixed cutter rotary drillbit or other downhole drilling tool. FIGS. 10B, 10D, 10F and 10H areschematic drawings showing portions of a composite bit face profile orcomposite cutting face profile corresponding with the components shownin respective FIGS. 10A, 10C, 10E and 10G. Blades and associated cuttingelements discussed with respect to FIGS. 10A-10H may be disposed onexterior portions of fixed cutter rotary drill bit 100, core bit 500and/or reamer 600. FIGS. 10A-10H show various examples of selectingrespective cutter groups for level one multilevel force balancing onassociated downhole drilling tool in accordance with teaching of thepresent disclosure.

Pair Cutter Group

A pair cutter group such as shown in FIG. 10A may be defined as a pairof cutting elements disposed on exterior portions of an associatedcutting face spaced radially between approximately 160° and 200° fromeach other relative to an associated bit rotational axis. The preferredradial spacing or optimum angle of separation for the first and secondcutting elements in a pair cutter group is approximately 180°. The firstcutting element and the second cutting element selected for a paircutter group must be neighbor cutters on an associated composite cuttingface profile with less than 100% overlap between associated cuttingsurfaces. The radius from the second cutting element to the associatedbit rotational axis must be greater than the radius from the firstcutting element to the associated bit rotational axis.

FIGS. 10A and 10B show one example of a “pair cutter group” representedby cutting elements 60 a and 60 b which may be disposed on exteriorportions of respective blades (not expressly shown). Cutting elements 60a and 60 b represent only one example of a pair cutter groupsatisfactory for use in level one force balancing an associated downholedrilling tool using multilevel force balancing procedures in accordancewith teachings of the present disclosure.

As shown in FIG. 10A, radial distance R2 from bit rotational axis 104 tocutting element 60 b is greater than the radial distance R1 from bitrotational axis 104 to first cutting element 60 a. Angle β betweencutting element 60 a and 60 b relative to rotational axis 104 isapproximately 170° which is greater than 160° and less than 200°.

As shown in FIG. 10B, cutting elements 60 a and 60 b satisfy thedefinition of “neighbor cutters” because cutting element 60 a andcutting element 60 b are disposed immediately adjacent to each other oncutting face profile 110 a with less than 100% overlap betweenrespective cutting surfaces 164 and cutting elements 60 a and 60 b.

Three Cutter Group

For some embodiments, cutting elements on a bit face or cutting face maybe assigned to respective three cutter groups for multilevel forcebalancing an associated downhole drilling tool in accordance withteachings of the present disclosure. A three cutter group (cuttingelements 60 a, 60 b, and 60 c) as shown in FIG. 10C may be defined asthree cutting elements disposed on exterior portions of an associatedcutting face spaced radially from each other between approximately 100°and 140° relative to an associated bit rotational axis. The preferredradial spacing or optimum angle of separation for the cutting elementsin a three cutter group is approximately 120°. The first, second andthird cutting elements selected for a three cutter group must beneighbor cutters on an associated composite cutting face profile withless than 100% overlap between associated cutting surfaces. The radiusfrom the third cutting element to the associated bit rotational axismust be greater than the radius from the second cutting element to theassociated bit rotational axis. The radius from the second cuttingelement to the associated bit rotational axis must be greater than theradius from the first cutting element to the associated bit rotationalaxis.

FIGS. 10C and 10D show one example of a “three cutter group” representedby cutting elements 60 a, 60 b and 60 c which may be disposed onexterior portions of respective blades (not expressly shown). Cuttingelements 60 a, 60 b and 60 c represent only one example of a threecutter group satisfactory for use in level one force balancing andassociated downhole drilling tools using multilevel force balancingprocedures in accordance with teachings of the present disclosure. Angleβ₁ between cutting elements 60 a and 60 b, angle β₂ between cuttingelements 60 a and 60 c and angle β₃ between cutting element 60 c and 60a are each greater than 100° and less than 140°. As shown in FIG. 10Cradial distance R₃ from third cutting element 60 c and bit rotationalaxis 104 is greater than radial distance R₂ from second cutting element60 b and bit rotational axis 104. Radial distance R₂ between cuttingelement 60 c and bit rotational axis 104 is greater than radial distanceR₁ between cutting element 60 a and bit rotational axis 104.

As shown in FIG. 10D, cutting elements 60 a, 60 b and 60 c satisfy thedefinition of “neighbor cutters” since cutting elements 60 a, 60 b and60 c are disposed adjacent to each other on composite cutting faceprofile 110 b with less than 100% overlap to respective cutting surfaces164 on the associated composite bit face profile 110.

Four Cutter Group

For some applications, cutting elements disposed on the cutting face ofa downhole drilling tool may be divided into respective four cuttergroups. A four cutter group such as shown in FIG. 10E may be defined asfour cutting elements disposed on exterior portions have an associatedcutting face spaced radially from each other with approximately with theangle of separation between the first and second cutter andapproximately equal to the angle of separation between the third andfourth cutting element. The angle of separation between the second andthird cutting element should be approximately equal to the angle ofseparation between the fourth cutting element and the first cuttingelement.

The first, second, third and fourth cutting elements of a four cuttergroup should be neighbor cutters on the associated cutting face profilewith less than 100% overlap. The fourth cutting element should be spacedat a greater radial distance from the associated bit rotational axisthan the third cutting element. The third cutting element should bespaced at a greater radial distance from the associated bit rotationalaxis than the second cutting element. The second cutting element shouldbe spaced at a greater radial distance from the associated bitrotational axis distance than the first cutting element.

As shown in FIGS. 10E and 10F angle β₁ between cutting element 60 a and60 b may be approximately equal to angle β₃ between cutting elements 60c and 60 d. Angle β₂ between cutting element 60 b and 60 c may beapproximately equal to angle β₄ between cutting elements 60 d and 60 a.Radius R4 extending between bit rotational axis 104 and cutting element60 d is greater than radius R3 extending from bit rotational axis tocutting element 60 c. Radius R3 associated with cutting element 60 c isgreater than radius R2 from bit rotational axis 104 and cutting element60 b. The length of radius R2 between bit rotational axis 104 andcutting element 60 b is greater than the length of radius R1 extendingbetween bit rotational axis 104 and cutting element 60 a. Cutters 60a-60 d on bit face profile 110 c as shown in FIG. 10H have less than100% overlap. Cutting elements 60 a, 60 b, 60 c and 60 d are neighborcutters on the associated bit face profile 110 c. See FIG. 10F.

Five Cutter Group

For some applications, the cutting elements disposed on exteriorportions of downhole drilling tool may be divided into five cuttergroups. The angle of separation (S) between each cutting element and afive cutter group may be approximately 72° plus or minus 20°. The first,second, third, fourth and fifth cutting elements of a five cutter groupshould be neighbor cutters on an associated cutting face profile withless than 100% overlap. The fifth cutting element should be spaced agreater radial distance from the associated bit rotational axis than thefourth cutting element. The fourth cutting element should be spaced at agreater radial distance from the associated bit rotational axis than thethird cutting element. The third cutting element should be spaced at agreater radial distance from the associated bit rotational axis than thesecond cutting element. The second cutting element should be spaced at agreater radial distance from the associated bit rotational axis than thefirst cutting element. For the example of a five cutter group as shownin FIGS. 10G and 10H cutting elements 60 a-60 e satisfy the above rules.

The cutters for each of the previously discussed cutter groups wereselected based on respective cutters being laid out in a spiralingdirection following the direction of rotation of the downhole drillingtool relative to an associated rotational axis. Similar cutter groupsmay also be selected for downhole drilling tools with cutters laid outin a spiraling direction reverse from the direction of rotation.

Blade Groups

The number of blades on a downhole drilling tool may be divided intogroups depending on the type of cutter groups used for level one forcebalancing. See table 301 in FIGS. 25A and 25B. The following examplesdemonstrate dividing blades into blade groups.

Example 1

The blades of a five blade downhole drilling tool as shown in FIG. 11Amay be divided into two blade groups: (1,3,5) and (2,4), where blades131, 133 and 135 form the first blade group and blades 132 and 134 formthe second blade group. The preferred match for a five blade downholedrilling tool is (1,3,5) (2,4) on table 301 in FIG. 25A. A three cuttergroup may be laid out on the first blade group (1,3,5). Imbalance forcescreated by the three cutter group may be balanced or minimized. A paircutter group may be laid out on the second blade group (2,4). Imbalanceforces created by the pair cutter group may be balanced or minimized.

Example 2

The blades of an eight blade downhole drilling tool as shown in FIGS.12A-12D may be divided into four blade groups: (1,5), (2,6), (3,7),(4,8). Four pair cutter groups may be laid out on the four blade groups.Imbalance forces created by each pair cutter group may be balanced orminimized. FIGS. 12A-12D show examples of selecting or laying locationsfor installing cutting elements of a downhole drilling tool inaccordance with teachings of the present disclosure.

Cutter Set

A cutter set includes at least two force balanced neighbor cuttergroups. The number of cutters in one cutter set may equal the number ofblades on an associated downhole drilling tool. As shown in table 301 ofFIG. 25A, a cutter set for a five blade downhole drilling tool may be[(1,3,5) (2,4)] and a cutter set for a eight blade downhole drillingtool may be [(1,5) (2,6) (3,7) (4,8)].

FIGS. 11A and 11B are schematic drawings showing portions of cuttingface 126 e and composite cutting face profile 110 e of a downholedrilling tool with five blades 131-135 disposed thereon. FIGS. 11A and11B show one example of cutting elements laid out for cutter set[(1,3,5) (2,4)]. Cutting elements 1, 2 and 3 in the first cutter groupmay be installed on primary blades 131, 133 and 135 and cutting elements4 and 5 in the second cutter group may be installed on secondary blades132 and 134.

Cutting elements 1, 2, 3 of the first cutter group are neighbor cutters.Cutting elements 4, 5 in the second cutter group are also neighborcutters. See composite cutting face profile 110 e in FIG. 11B. Imbalanceforces created by respective cutting elements in each cutter group maybe balanced or minimized by adjusting respective cutter locations,cutter orientations such as back rake, side rake, cutter size and phaseangle. See for example arrows 188 a and 188 b in FIG. 21A.

Level Three and Level Four Force Balanced Cutter Sets

Similar to level four force balanced drilling tools, imbalance forcesassociated with each cutter set may be balanced at three levels inaccordance with teachings of the present disclosure. Level one forcebalancing of a cutter set balances forces associated with the cuttingelements in each cutter group. See, for example, FIGS. 10A-10H. Leveltwo force balancing of a cutter set balances forces associated with thecutting elements in any two neighbor cutter groups in the cutter set.See, for example, FIGS. 11A and 11B. Level three force balancing of acutter set balances forces associated with all cutting elements in thecutter set.

For example, cutter set [(1,3,5) (2,4)] of a five blade downholedrilling tool shown in FIGS. 11A AND 11B and cutter set [(1,5) (2,6)(3,7) (4,8)] of an eight blade downhole drilling tool shown in FIG. 12Aare level three force balanced cutter sets.

Some cutter sets may be level four force balanced cutters sets. Levelfour force balancing of a cutter set calls for balancing forcesassociated with an N (N=3 or N=4) consecutive cutting elements in thecutter set. As shown in FIGS. 12A-12D, a downhole drilling tool witheight blades 131-138 has four basic pair blade groups [(1,5), (2,6),(3,7), (4,8)]. Depending on the order of the blade groups in each cutterset, at least six cutter sets may be formed if blade group (1,5) isalways kept as the first group:

Cutter Set A: [(1,5) (2,6) (3,7) (4,8)]

Cutter Set B: [(1,5) (2,6) (4,8) (3,7)]

Cutter Set C: [(1,5) (3,7) (4,8) (2,6)]

Cutter Set D: [(1,5) (3,7) (2,6) (4,8)]

Cutter Set E: [(1,5) (4,8) (3,7) (2,6)]

Cutter Set F: [(1,5) (4,8) (2,6) (3,7)]

The following description discusses imbalance forces associated with anyfour consecutive cutting elements (1,2,3,4), (2,3,4,5), (3,4,5,6),(4,5,6,7), (5,6,7,8).

As shown in FIG. 12A, cutter set A [(1,5) (2,6) (3,7) (4,8)] is used tolayout cutters on bit face 126 f. Imbalance forces associated withcutters (2,3,4,5) may not be balanced because these four cutters arelocated on one side of the bit face 126 f. Imbalance forces associatedwith cutters (4,5,6,7) also may not be balanced for the same reason.Therefore, cutter set A [(1,5) (2,6) (3,7) (4,8)] is not a level fourforce balanced cutter set.

As shown in FIG. 12B, cutter set B [(1,5) (2,6) (4,8) (3,7)] is used tolayout cutters on bit face 126 g. Imbalance forces associated withcutters (2,3,4,5) and imbalance forces associated with cutters (6,7,8,9)may not be balanced because these cutters are located on one side of bitbody, respectively. Therefore, cutter set B [(1,5) (2,6) (4,8) (3,7)] isnot a level four force balanced cutter set.

As shown in FIG. 12C, cutter set C [(1,5) (3,7) (4,8) (2,6)] is used tolayout cutters on bit face 126 h. Imbalance forces associated withcutters (2,3,4,5) and imbalance forces associated with cutters (6,7,8,9)may not be balanced because these cutters are located on the same sideof cutting face 126 h. Therefore, cutter set C [(1,5) (3,7) (4,8) (2,6)]is not a level four force balanced cutter set.

As shown in FIG. 12D, cutter set D [(1,5) (3,7) (2,6) (4,8)] is used tolayout cutters on bit face 126 i. Imbalance forces associated withneighbor cutter groups (1,2,3,4), (3,4,5,6) and (5,6,7,8) may be wellbalanced. Respective imbalance forces associated with cutters (2,3,4,5)and (4,5,6,7) may be minimized because the angle between these cuttersis over 220 degrees. Therefore, cutter set D [(1,5) (3,7) (2,6) (4,8)]may be a level four force balanced cutter set.

Table 302 in FIG. 26 shows the preferred match for an eight bladedownhole drilling tool. Cutter layout using cutter set D for an eightblade downhole drilling tool may lead to more stable balanced drillingthan cutter sets A, B and C and therefore is the preferred cutter set.

The cutting faces shown in FIG. 12A-12D demonstrate that the order ofneighbor cutter groups within a cutter set may play a significant rolein design of multilevel force balanced downhole drilling tools. Ifseveral cutter sets exist for a given number of blades, then level fourforce balanced cutter sets should first be considered for laying outcutter locations. For downhole drilling tools with only three or fourblades, level four force balanced cutter sets may not exist. Only levelthree force balanced cutter sets may be available.

For a given number of blades, Table 301 in FIGS. 25A and 25B listspossible cutter sets. Table 302 in FIG. 26 lists preferred level fourforce balanced cutter sets for a given number of blades. The number ofconsecutive cutting elements N (N=3 or N=4) used for level four forcebalancing depends on the number of blades and cutter sets. For example,for a nine blade drill bit, if cutter set [(1,4,7) (2,5,8) (3,6,9)] isused to layout cutters, then N=3. See FIGS. 17 and 26.

Outer Cutter Set

If cutter layout is outwards such as from a nose point to an associatedgauge pad, then the outer cutter set is the same as the cutter setdefined above. For example, for a seven blade bit using three cuttergroups, outer cutter set may be [(1,4,6) (2,5) (3,7)]. FIGS. 13A and 13Bshow the cutter distributions on bit face 126 j and bit face profile 110j for cutters in an outer cutter set. Bit face profile 110 j in FIG. 13Bindicates that outer cutting elements in each cutter group satisfy thegeneral rule that radial distance from an associated rotational axis tothe second cutting element in a cutter group must be greater than theradial distance to the adjacent to the first cutting element. It isnoted that the radial location of the cutters within the outer cutterset meets the following rule:

R_(i+1)>R_(i) i=1,2,3 . . .

Inner Cutter Set

If cutter layout is inwards such as from nose point to bit center, thenthe blade order in an inner cutter set is reverse of the blade order ofthe outer cutter set. For example, if the outer cut set is [(1,4,6)(2,5) (3,7)], then the inner cutter set is: [(7,3) (5,2) (6,4,1)]. FIGS.13C and 13D show the cutter distributions on bit face and on bit profilefor cutters in an inner cutter set.

Blade Order for all Outer Cutters

If cutter layout is outward from a nose point on a cutting face profileand more than one outer cutter set is required, the blade order for allouter cutters is a repeat of the first outer cutter set. For an eightblade bit using cutter set [(1,5) (3,7) (2,6) (4,8)], the blade orderfor all outer cutters is: [1 5 3 7 2 6 4 8, 1 5 3 7 2 6 4 8, 1 5 3 7 2 64 8, . . . ]

Blade Order for all Inner Cutters

If cutter layout is inward from a nose point on a cutting face profileand more than one inner cutter set is required, the blade order for allinner cutters is a repeat of the first inner cutter set. For an eightblade bit using cutter set [(1,5) (3,7) (2,6) (4,8)], the blade orderfor all inner cutter sets is: [8 4 6 2 7 3 5 1, 8 4 6 2 7 3 5 1, 8 4 6 27 3 5 1, . . . ]

FIG. 14 is a schematic drawing showing portions of cutting face 126 k ofa prior art rotary drill bit with six blades 131-136 extending radiallyfrom bit rotational axis 104. FIG. 14 shows potential problems withprior techniques to select or layout locations for installing cuttingelements on exterior portions of a downhole drilling tool from alocation proximate the rotational axis. As shown in FIG. 14, first end141 of each primary blade 91, 93, 95 may be disposed closely adjacent tobit rotational axis 104. First end 141 of each secondary blade 92, 94and 96 may be radially spaced from bit rotational axis 104.

Prior procedures for selecting locations for installing respectivecutting elements on exterior portions of associated blades generallystart with selecting the first location closely adjacent to theassociated rotational axis. For the example shown in FIG. 14, thelocation for installing cutting element 1 was selected closely adjacentto first end 141 of blade 91 and also closely adjacent to rotationalaxis 104.

The location for installing the second cutting element on exteriorportions of an associated blade is generally selected based on desiredoverlap with the first cutting element in a spiraling direction from thelocation for the first cutting element in either the direction ofrotation or reverse to the direction of rotation. For cutting face 126 kin FIG. 14, the location for installing cutting element 2 was selectedon blade 93 spaced radially from bit rotational axis 104 in thedirection of rotation. See arrow 28. Cutting element 3 may be installedon exterior portions of blade 95 at a greater radial distance ascompared with cutting element 2 in the direction of bit rotation. Thesequence of installing additional cutting elements may continuegenerally in the direction of rotation of an associated downhole drillbit.

Potential problems from using the prior procedures include the largedistance between locations for installing cutting elements 4 and 8 onblade 91 which result in uneven cutter loading. Also, substantial gapsextend from respective first end 141 of secondary blades 92, 94 and 96.Primary blade 93 may have excessively large gaps between cuttingelements 5 and 12.

FIGS. 15A and 15B show two examples of selecting or laying out cuttingelements starting at or near a nose point on an associated compositecutting face profile in accordance with teachings of the presentdisclosure. The resulting cutter groups may be arrangedpseudo-symmetrical relative to the nose point on the composite cuttingface profile.

Portions of cutting face 126 m shown in FIG. 15B may include primaryblades 131, 133 and 135. First end 141 of each primary blade may bespaced closely adjacent to associated bit rotational axis 104. Thelocation for installing cutting element 1 on primary blade 131 may beselected to be closely adjacent to nose point 171 and associated nosecircle 174. The location for installing second cutting element 2 may beselected on primary blade 135 spaced radially inward relative to cuttingelement 1 and also in a radial direction opposite from the direction ofrotation indicated by arrow 28. Cutting element 3 may also be disposedproximate the associated nose point. As a result, cutting elements 1, 2and 3 may be disposed generally symmetrical to each other around noseaxis 172 on the associated composite cutting face profile 110 m as shownin FIG. 15A. A first group of outer cutting elements 4, 5 and 6 may bedisposed or at locations on exterior portions of associated bladesextending at a greater radial distance from the nose point 171. Cuttingelements 4, 5 and 6 may be laid out outwardly from nose point 171 to anassociated gage pad or gage cutter. The blade order for installing theouter cutting elements 4, 5 and 6 may follow the predefined order sothat transient imbalance forces associated with all outer cutterelements may be balanced. After layout of the location for all outercutting elements, a first group of inner cutting elements 4, 5 and 6 maythen be disposed at locations spaced radially inward relative to dottedcircle 174 in FIG. 15B and nose axis 172 in FIG. 15A. The locations foradditional inner cutting elements may also be laid out extending fromnose point 171 to bit rotational axis 104. As shown in FIG. 15, theresulting gaps may be substantially minimized and desired overlapprovided with respect to the inner cutters and the outer cutters.

For some embodiments not expressly shown, the initial location forinstalling the first cutting element may be selected on a secondaryblade such as secondary blade 132, 134 or 136. Since the location forinstalling the first cutting element is no longer required to beimmediately adjacent to the bit rotational axis, the locations forinstalling the first cutting element may be selected on the secondaryblades. The blade order for secondary locations for respective cuttingelements may proceed in the predefined order to minimize transientimbalance forces. The importance of selecting locations for laying outor installing cutting elements from a nose point or near a nose pointare shown in FIGS. 19A, 19B and 20A-20D.

For examples shown in FIG. 15A, cutting elements 1, 2 and 3 may bedisposed at locations generally symmetrically or arranged relative tonose point 171 and nose axis 172. The first group of outer cutters(4,5,6) may also be balanced with respect to each other and with respectto nose cutters (1,2,3). The first group of inner cutters (4,5,6) may bebalanced with respect to each other and with respect to nose cutters(1,2,3). As a result, contact between downhole drilling tool having acomposite cutting face profile such as shown in FIG. 15A maysubstantially reduce or eliminate imbalance forces resulting inengagement with downhole formations during transition drilling such asshown in FIGS. 7 and 22.

Problems associated with uneven loading of blades such as FIG. 14 andundesired or void spaces or gaps with blades such as 92, 94 and 96 mayresult in uneven loading of cutting elements 1-17.

One aspect of the present disclosure includes laying out cuttingelements starting from the nose or near nose of a composite bit faceprofile.

The above described problems may be partly overcome by layout cutterfrom nose or near nose. If cutter layout starts from the nose point,then outwards to bit gauge pad, blade order of all outer cutters canfollow exactly the pre-defined order so that transient imbalance forcesassociated with all outer cutters can be balanced. After layout outercutters, inner cutters are layout from nose point inwards to bit center.In this way, some naked portion shown in FIG. 14 may be covered bycutters because cutters are usually first considered to be located closeto nose point.

Cutter layout may also start near the nose point. For example, the startlayout point may be the start point of the secondary blade and the firstcutter may be located on the secondary blade. In this way, blade orderof cutters outside of the start point can follow exactly the pre-definedorder so that transient imbalance force can be balanced for theseoutside cutters.

The importance of starting layout cutters from a nose point or near anose point on an associated composite cutting face profile may befurther demonstrated by comparing FIGS. 19A, 19B and 20A-20G with FIGS.21A, 21B and 22A-22J. If cutter layout starts from the nose point, thencutter groups on left and right sides of nose point may be first placedso imbalance forces associated with these cutters may be balanced.

Cutter Arrangement within Nose Zone

FIG. 15A shows the benefits of placing at least three cutter groupsproximate an associated nose zone. The first cutter group, cutters(1,2,3), is located around the nose point, the second cutter group,cutters (4,5,6), is on the outside of the first group and the thirdcutter group, inner cutters (4,5,6), is on the inner side of the firstcutter group. The cutter groups should be arranged so that imbalancedforces associated with each cutter group are balanced and imbalanceforces associated with the three groups are also balanced. This type ofcutter arrangement may be called pseudo-symmetrical cutter groups aroundnose point.

Usually if bit hydraulics is allowed, at least three cutter sets shouldbe placed around nose zone. The first cutter set is located around thenose point, the second cutter set is on the outside of the first cuterset and the third cutter set is on the inner side of the first cutterset. These cutter sets should be arranged so that imbalance forcesassociated with each cutter set are balanced and imbalance forcesassociated with these three cutter sets are also balanced.

Generally, placing more pseudo-symmetrical cutter sets around a nosepoint will improve force balancing of a downhole drilling tool.Carefully selecting the location of the first end of secondary bladesmay be important to ensure that a resulting cutter layout includespseudo-symmetrical arrangement of cutting elements relative to a noseaxis. This usually requires at least the first end of secondary bladesassociated with the third cutter group or cutter set is within the noseradius.

FIG. 24A is a schematic drawing showing an end view of fixed cutterrotary drill bit 100 c. Fixed cutter rotary drill bit 100 c may have aplurality of blades 131 c-136 c disposed on exterior portions ofassociated bit body 120 c. Dotted circle 174 may correspond withrespective nose point 171 on exterior portions of respective blades 131c-136 c. Radius of dotted circle 174 may correspond with the distancebetween bit rotational axis 104 and nose axis 172 as shown in FIG. 24B.For some applications, respective cutting elements 60 n may be disposedclosely proximate to nose points 171 on each blade 131 c-136 c.Resulting bit face profile 110 c is shown in FIG. 24B.

For this embodiment, cutting elements 60 n have approximately 100%overlap with each other on bit face profile 110 c. Therefore, cuttingelements 60 n do not meet the requirement of “neighbor cutters” forpurposes of multiforce level balancing techniques. However, installing alarge number of cutting elements proximate the nose point of rotarydrill bits and other downhole drilling tools may substantially improvestability during initial contact with a downhole formation or duringtransition drilling from a first generally hard formation from a firstgenerally soft formation into a second generally harder formation.

For the other applications, nose cutters 60 n may only be disposed onnose points associated with primary blades 131 c, 133 c and 135 c (notexpressly shown) at approximately the same angle relative to each otherand relative to bit rotational axis 104. For such applications cuttingelements 60 n may be located at approximately the same radial distancefrom associated bit rotational axis 104 and at the height from referenceline 108 extending generally perpendicular to bit rotational axis 104.For other applications two blades (not expressly shown) may be spacedapproximately one hundred eighty degrees (180°) from each other or fourblades (not expressly shown) may be spaced approximately ninety degrees(90°) from each other or five blades (not expressly shown) approximatelyseventy two degrees (72°) from each other or six blades (not expresslyshown) may be spaced approximately sixty degrees (60°) from each otheror seven blades (not expressly shown) may be spaced approximately 51.42°from each other, etc.

The above descriptions on cutter layout assumed cutter layout spiralgenerally follows the direction of bit rotation because most of today'sPDC bits are designed this way.

However, if the cutter layout spiral direction reverses bit rotation,the cutter layout principle described above may also be used. FIG. 15Bdepicts an example of a 6 blade bit whose cutter layout reverses bitrotation.

Algorithm 1: Two Blade Groups

If the algorithm for two blade groups is used, then the preferred numberof blades in each blade group should be as close as possible. Fordownhole drilling tool with ten (10) blades such as shown in FIG. 16A,the preferred two blade groups may be (1,3,5,7,9) and (2,4,6,8,10). Ifthe primary blades are (1,3,5,7,9) and cutter layout starts from thenose point 171 or near nose point 171, then the preferred cutter set is[(1 3 5 7 9) (2 4 6 8 10)]. FIG. 16A shows cutting face 126 n withresulting layout for nose cutters 1, 2, 3, 4 and 5 disposed at or nearrespective nose points 171 corresponding with circle 174 when the twoblade groups' algorithm is used.

If the primary blades are (1,3,5,7,9) or 131, 133, 135, 137 and 139 asshown in FIG. 16A and layout cutter starts from a start point of one ofthe secondary blades 132, 134, 136, 138 or 140, then the preferredcutter set becomes [(2,4,6,8,10) (1,3,5,7,9)]. Other two blade groupsmay be used to layout or select locations for installing cuttingelements on a downhole drilling with 10 blades. For example, two bladegroups may be used because 10=4+6, the first blade group will have fourblades and the second blade group will have six blades.

Algorithm 2: Pair Blade Groups

There are five possible pair groups for a downhole drilling tool withten blades: (1, 6), (2,7), (3, 8), (4,9), (5,10). If the primary bladesare (1,4,6,9) as shown in FIG. 16B, then the preferred cutter set is[(1,6) (4,9) (2,7) (5, 10) (3,8)].

As listed in Table 301 of FIG. 25A, there may be other types of cuttersets for a ten blade downhole drilling tool by reordering the bladegroups, for example, cutter set [(1,6) (2,7) (3,8) (4,9) (5,10)] may beused for cutter layout. However, cutter set [(1,6) (2,7) (3,8) (4,9)(5,10)] may only be level three force balanced. The preferred cutter set[(1,6) (4,9) (2,7) (5,10) (3,8)] may be level four force balanced.Therefore, using the preferred cutter set for cutter layout ten bladedownhole drilling tool may provide better lateral stability.

Algorithm 3: Three Blade Groups

Cutting face 126 q as shown in FIG. 16C four primary blades 131, 134,136 and 139. The blades may be divided into three blade groups[(1,4,6,9) (2,5,8) (3,7,10)]. The preferred cutter set is [(1,4,6,9),(3,7,10), (2, 5, 8)] which is level four force balanced. FIG. 16Cdepicts the cutters layout when three groups algorithm is used.

As listed in Table 301 of FIG. 25B, there may be other types of cutterset for a ten blade downhole drilling tool using three blade groups. Forexample, cutter set [(1,3,6,8) (2,5,9) (4,7,10)] may be used to layoutcutters but it may be only level three force balanced.

Algorithm 4: Four Blade Groups

Cutting face in FIG. 16D has only three primary blades 131, 134 and 137.Four cutter groups and cutter set [(1,4,7) (3,8) (5,10) (2,6,9)] may beused to select or layout locations for installing cutting elements onexterior portions of blades 131-140. This cutter set may only be levelthree force balanced. Examples of other cutter sets which may also beused are shown in Table 301 of FIG. 25B.

Other Algorithms: Five Blade Groups, Six Blade Groups and Seven BladeGroups

If the number of blades on a downhole drilling tool is M, then themaximum number of blade groups may be estimated by the integer part ofM/2. For example, for a downhole drilling tool has fifteen (15) blades,the blades may be divided into a maximum of 7 groups. Therefore, for adownhole drilling tool with 15 blades, at least six algorithms may beused:

Two blade groups: 15=7+8;

Three blade groups: 15=5+5+5;

Four blade groups: 15=3+4+4+4;

Five blade groups: 15=3+3+3+3+3;

Six blade groups: 15=3+3+3+2+2+2;

Seven blade groups: 15=3+2+2+2+2+2+2;

Selected cutter sets for some of algorithms are listed in Table 301 inFIGS. 25A, 25B and 26.

Blade Order Violations & Algorithm

There are two cases in which the above pre-defined blade orders,especially blade orders for inner cutter sets, may violate multiforcelevel balancing requirements.

Case 1: Minimal and Maximal Distance Between Two Neighbor Cutters on theSame Blade

The distance between any two adjacent cutters (not on the same blade) onan associated composite cutting face profile is determined by a givendesign overlap ratio of neighbor cutting surface. Overlap ratio of twocutters is defined by the shared area divided by the sum of areas of twocutters. For example, 100% overlap of neighbor cutting surfaces resultsin zero distance between the two cutters on the composite cutting faceprofile. The desired overlap between any two neighbor cutters on anassociated cutting face profile is usually less than 100% and most oftenbetween 20% to 90% in accordance with teachings of the presentdisclosure.

The pre-defined overlap and pre-defined blade orders may lead to thedistance between two neighbor cutters on the same blade being either toosmall or too large. If this distance is too small, there may be notenough space on a blade to install a cutting element. If this distanceis too large, then at least one of the cutters may remove too much rockand may subject to increased forces as compared to cutters with properoverlap.

Satisfaction of distance requirement between two neighbor cutters on thesame blade may lead to violation of blade orders, especially blade orderfor inner cutters. Iteration is usually needed to avoid this situationby carefully adjusting overlap ratio, cutter size, side rake angle andother design parameters.

Case 2: Incomplete Cutter Group or Incomplete Cutter Set

The pre-defined blade orders, either for inner cutters or for outercutters, are repeated by cutter set. The number of cutters on a downholedrilling tool divided by the number of cutters in a cutter set may benot equal an integer. Several last cutters may not belong to anypre-defined cutter groups or cutter sets.

For example, for an eight blade on a downhole drilling tool using cutterset [(1,5) (3,7) (2,6) (4,8)], and starting layout cutters from the nosepoint, then the predefined blade orders for all inner cutters are: [8 46 2 7 3 5 1, 8 4 6 2 7 3 5 1]

However, if only 9 cutters may be put on inner blades and the resultedblade order for the 9 cutters becomes: [8 4 6 2 7 3 5 1, 8]

The last cutter (or the cutter closet to bit center), cutter 9 is onblade 8 and does not belong to any cutter group. The imbalance forcescreated by cutter 9 may not be balanced.

If the start radii of the secondary blades 2 and 6 are outside of thenose point, then the blade orders for inner cutters may become: [8 4 7 35 1, 7 3 5 1].

The first cutter set becomes incomplete. The imbalance forces associatedwith an incomplete cutter set may not be balanced.

A downhole drilling tool of method 700 shown in FIGS. 23A and 23B may beneeded to avoid this situation by adjusting the starting point of cutterlayout, overlap ratio for inner cutters, cutter size, side rake angle,phase angle and other design features.

Choice of Cutter Layout Algorithms

Many algorithms may be used for a downhole drilling tool with a givennumber of blades. For each cutter layout algorithm, there may be manycutter sets to chose from. A downhole drilling tool designer shouldfirst choose which algorithm to use and then choose which cutter set touse. Selected cutter sets for a given number of blades are listed ifFIGS. 25A, 25B and 26.

Three rules should generally be followed for choosing a cutter layoutalgorithm and choosing a force balanced cutter set.

First Rule:

Preferred number of cutters in a blade group is either 2 or 3. If thenumber of blades is even, then pair blade group algorithm should beused. For example, for an eight blade bit, the preferred cutter layoutalgorithm should be pair blade group algorithm. If the number of bladesis odd, then number of blade in each blade group should be either 2 or3. For a downhole drilling tool with seven blades, the preferred numberof blade groups should be three, namely, 7=3+2+2. Therefore, the threeblade group algorithm should be used.

Second Rule:

The number of cutters in each cutter group should be as close aspossible.

For the two blade group algorithm, if the number of blades is even, thenthe first and second blade groups will have the same number of blades.If the number of blades is odd, then one blade group has K blades andanother blade group has K+1 blades where 2K+1 equals the number ofblades.

A downhole drilling tool with nine blades may be used to furtherdemonstrate this rule. Two algorithms may be used as listed in FIGS. 25Aand 25B:

Three blade groups: 9=3+3+3; and

Four blade groups: 9=3+2+2+2.

The three blade group algorithm may be better than the four blade groupalgorithm because the three blade group algorithm may create moresymmetrical cutting structure than the four blade group algorithm.

Third Rule:

Level four force balanced cutter sets should be as preferred over levelthree force balanced cutter sets. This rule was demonstrated for adownhole drilling tool with eight blades in FIG. 12D. The preferredcutter set [(1,5) (3,7) (2,6) (4,8)] may be level four force balancedwhich should be used in cutter layout.

Rule three may be further demonstrated for a downhole drilling tool withnine blades and imbalance forces created by any three neighbor cuttergroup: [(1,2,3) (2,3,4) (3,4,5) (4,5,6) (5,6,7) (6,7,8) (7,8,9)]. If thethree cutter group algorithm and the preferred cutter set [(1,4,7)(2,5,8) (3,6,9)] are used, the cutter layout is shown in FIG. 17.Imbalance forces associated with any three neighbor cutters [1,2,3)(2,3,4) (3,4,5) (4,5,6) (5,6,7) (6,7,8), (7,8,9) may be balanced orminimized because the degrees of separation between any these cuttersrelative to rotational axis 104 is over one hundred eighty (180°)degrees.

On the other hand, FIG. 18 shows cutter layout where four groupalgorithm is used with cutter set [(1,4,7) (3,8) (5,9) (2,6)]. Among anythree neighbor cutters (1,2,3) (2,3,4) (3,4,5) (4,5,6) (5,6,7) (6,7,8)(7,8,9) imbalance force associated with (2,3,4), (5,6,7) and (7,8,9) maynot be balanced or minimized because three cutters are located on thesame side of cutting face 110A.

Therefore, a nine blade bit designed by three group algorithm usingcutter set [(1,4,7) (2,5,8) (3,6,9)] should be more stable than thatdesigned by four group algorithm using cutter set [(1,4,7) (3,8) (5,9)(2,6)] using multilevel force balancing procedures.

Design Procedure of Multilevel Force Balanced Downhole Drilling Tool

FIGS. 19A and 19B show various features associated with rotary drill bit90 a which may be force balanced using traditional one level forcebalancing techniques and traditional cutter layout procedures startingfrom bit rotational axis 104. FIGS. 20A-20D show examples of transientimbalance forces which have not been satisfactorily balanced based onsimulations of rotary drill bit 90 while forming a wellbore throughnon-uniform downhole drilling conditions.

FIGS. 21A and 21B show various features associated with rotary drill bit100 which may be multilevel force balanced in accordance with teachingsof the present disclosure. FIGS. 22A-22J show various examples ofimbalance forces acting on rotary drill bit 100 which may besubstantially reduced or eliminated (balanced) by designing andmanufacturing fixed cutter rotary drill bit 100 based at least in parton multilevel force balancing techniques and cutter layout proceduresincorporating teachings of the present disclosure.

Rotary drills bits 90 a and 100 may be generally described as eightblade fixed cutter rotary drill bits. Respective blades 91-98 on rotarydrill bit 90 a and blades 131-138 on rotary drill bit 100 may have thesame configuration and dimensions relative to respective bit rotationalaxis 104. Rotary drill bit 90 a and 100 may have the same number, sizeand type of cutting elements.

FIG. 19B shows composite bit face profile 192 associated with rotarydrill bit 90 a resulting from installing cutting elements 1-75 on blades91-98 using traditional one level force balancing techniques and layingout cutter locations relative to bit rotational axis 104. FIG. 22B showscomposite bit face profile 110 resulting from installing cuttingelements 1-72 on blades 131-138 based on multilevel force balancingtechniques and laying out cutter locations relative to nose segment 170,nose point 171 and nose axis 172 in accordance with teachings of thepresent disclosure.

In FIGS. 19A and 19B, the cutting elements on rotary drill bit 90 a havebeen numbered from 1 through 75 on cutting face 190 and composite bitface profile 192. Cutting elements disposed on blades 91-98 have beennumbered sequentially 1-75 in a spiraling order from bit rotational axis104 in the direction of bit rotation.

The locations for installing cutting elements 1-75 for rotary drill bit90 a were selected starting from associated bit rotational axis 104 in adirection corresponding generally with the direction of rotationstarting with cutting element 1 disposed immediately adjacent to bitrotational axis 104 at the first end of blade 91. Exterior portions ofthe blades 91-98 on which cutting elements 1-75 are disposed are notexpressly shown in FIG. 19A.

As shown in FIG. 19A the location for installing cutting element 1 wasselected on blade 91 proximate bit rotational axis 104. The locationselected for installing cutting element number 2 is on blade 93 at agreater radial distance from bit rotational axis 104 than cuttingelement 1. The location for installing cutting element 3 is on blade 95a greater radial distance from bit rotation axis 104 as compared withcutting element 2. The remaining cutting elements 4-75 may be installedon blades 91-98 at locations selected in the same direction of bitrotation as represented by arrow 28. The orientation, size, etc. ofcutting elements 1-75 on cutting face 190 of rotary drill bit 90 a maybe adjusted to satisfy the requirement of traditional one level of forcebalancing.

FIGS. 20A-20D show the bit imbalance forces during transition drillingof a generally non-uniform formation such as shown in FIG. 7. FIG. 20Eshows the magnitude of the lateral force ratio of each individual cutterwhen all of the cutters on composite bit face profile 192 drill into auniform formation. FIG. 20F shows the magnitude of the lateral forceratio of any two consecutive neighbor groups of cutters when all of thecutters drill into a uniform formation. FIG. 20G shows the magnitude ofthe lateral force ratio of any four consecutive neighbor groups ofcutters when all of the cutters drill into a uniform formation.

Except for some inner cutters (1-12), lateral imbalance forcesassociated with the four neighbor cutter groups are greater than lateralimbalances forces with each individual cutting element 1-75. The maximumlateral imbalance force shown in FIG. 20A may be as high asapproximately 11% of the total axial force applied to rotary drill bit90 a. The maximum bending moment applied to rotary drill bit 90 a may beas high as 35% of bit torque during initial engagement with the end of awellbore. See FIG. 20D. During transition drilling from one downholeformation with a compressive strength of approximately 5,000 psi to asecond downhole formation with a compressive strength of approximately18,000 psi transient bit lateral imbalance forces may be as high as 5%of the bit axial force. The axial bending moment applied to fixed cutterrotary drill bit 90 a during transit drilling from formation layer 41 toformation layer 42 may be approximately 7.5% of the associated bittorque. Bit imbalance forces only return to a satisfactory level whenall cutting elements disposed on exterior portions of rotary drill bit90 a are engaged with a generally uniform downhole formation eitherformation layer 41 or 42.

FIGS. 21A and 21B show various features of rotary drill bit 100 whichmay be multi force level balanced using methods and procedures such asshown in FIG. 1D and FIGS. 23A and 23B. Locations for installing cuttingelements 1-72 on cutting face 126 of rotary drill bit 100 may beselected starting from nose point 171 or nose axis 172 in accordancewith teachings of the present disclosure. See for example FIG. 25B.

In FIG. 21A two numbers are provided for each cutting element. Thenumbers written in front of cutting face 164 of each cutting elementcorresponds with the sequence in which locations were selected or laidout for installing each cutting element on respective blades 131-138. Asecond number is written on top of each cutting element correspondingwith the sequence in which each cutting element may be installed onexterior portions of associated blade 131-138. Cutting elements areoften installed in pockets or sockets disposed (not expressly shown) onexterior portions of a blade.

Fixed cutter rotary drill bit 100 may be generally described as rotarydrill bit 90 a with locations for installing cutting elements 1-72redesigned using the pair group algorithm for an eight blade downholedrill tool shown on table 302 in FIG. 26. The preferred level four forcebalanced cutter set is [(1,5,) (3,7) (2,6) (4,8)] on table 302. Thestarting point for installing cutting elements on the exterior portionsof fixed cutter rotary drill bit 100 is preferably nose point 171 ornose axis 172 on composite bit face profile 110 as indicated in FIG.21B. Nose cutters 1 and 2 as shown in FIG. 21B may correspond generallywith nose cutters 60 n as shown in FIG. 1B. In FIG. 21A respective phaseangles represented as arrows 188 a and 188 b are shown extending fromnose cutters 1 and 2 as shown in FIG. 21B. As previously noted, the pairgroup algorithm for an eight bladed bit was used to select locations forinstalling cutting elements 1-72 on exterior portions of blades 131-138.Nose cutters 1 and 2 as shown in FIGS. 21A and 21B may also be describedas the pair cutter group proximate nose point 171.

The location for installing cutting elements in outer segment 180 may beselected starting from nose cutter 2 on blade 135. Phase angle arrow 188b extends from nose cutter 2. For the embodiment shown in FIG. 21A, thelocation for installing the first outer cutter is selected on primaryblade 133. The location for installing the second outer cutter is shownon blade 137.

Large bold numbers 1 and 2 in FIG. 21A correspond with nose cutters 1and 2 in FIG. 21B.

The location for installing additional cutting element for additionalouter cutters may be selected in a direction corresponding with thedirection of rotary drill bit 100 as indicated by arrow 28.

Inner cutters disposed on exterior portions of fixed cutter rotary drillbit 100 may be selected or laid out as shown in FIG. 21B extending fromnose axis 172 to bit rotational axis 104.

FIGS. 22A-22D indicate that bit imbalance forces during transitiondrilling such as shown in FIG. 7 may be substantially reduced oreliminated (e.g., balanced). The cutter numbers listed in FIGS. 22E-22Jcorrespond with the sequence in which the cutting elements are installedon rotary drill bit 100 starting from a location 1 proximate bitrotational axis 104.

FIG. 22E shows the magnitude of the lateral force ratio of eachindividual cutter when all of the cutters drill into a uniformformation. The magnitude of the lateral force of each cutter is betweenapproximately 1% and approximately 3% of the bit axial force. FIG. 22Fshows the phase angle of the lateral force of each individual cutter.

FIG. 22G shows the magnitude of the lateral force ratio of each cuttergroup when all of the cutters drill into a uniform formation. Thelateral force of each cutter group is less than that of an individualcutter in the same group. The magnitude of the lateral force for mostcutter groups is between approximately 0.3% and approximately 0.77% ofthe bit axial force. Therefore, drill bit 100 is level one forcebalanced.

FIG. 22H shows the magnitude of the lateral force ratio of any twoconsecutive neighbor groups of cutters when all of the cutters drillinto a uniform formation. The lateral force of each of the twoconsecutive neighbor groups is less than that of an individual cutter inthe same two neighbor groups. The magnitude of the lateral force formost two neighbor cutter groups is between approximately 0.45% andapproximately 0.85% of the bit axial force. Therefore, drill bit 100 islevel two force balanced.

FIG. 22I shows the magnitude of the lateral force ratio of each cutterset when all the cutters drill into a uniform formation. The lateralforce of each cutter set is less than that of an individual cutter inthe same set. The maximum magnitude of the lateral force for all cuttersets is less than approximately 0.91% of the bit axial force. Therefore,drill bit 100 is level three force balanced.

FIGS. 22J-1 and 22J-2 show the magnitude of the lateral force ratio ofany four consecutive neighbor groups of cutters when all of the cuttersdrill into a uniform formation. The lateral force of each of the fourconsecutive neighbor cutters is less than the maximum lateral force ofeach individual cutter in the same four consecutive neighbor groups ofcutters. The maximum magnitude of the lateral force for any fourconsecutive neighbor groups of cutters is less than approximately 1.72%,where most magnitudes of the lateral force are less than approximately0.6% of the bit axial force. Therefore, drill bit 100 is level fourforce balanced.

Graph 200 b of FIG. 22A shows the results of simulating drillingwellbores 30 a and 30 b as shown in FIG. 7 using fixed cutter rotarydrill bit 100. The maximum bit lateral imbalance force represented bypeak 201 b is approximately 4.5%. The remaining peaks associated withgraph 200 b are generally less than 3% which corresponds favorably withgenerally flat segments 204 b and 208 b when cutting elements 1-72 areengaged with generally uniform downhole formation layers 41 and 42respectively. In graph 220 b of FIG. 22B, the maximum drag lateralimbalance force at peak 21 b is approximately only 4% of total bit axialforce. FIG. 22B also shows that drag lateral imbalance force duringgenerally flat segments 213 b and 216 b is less than 2% of total bitaxial force. The same comments apply with respect to graphs 230 b and240 b respectively shown in FIGS. 22C and 22D. The peak radial imbalanceforce is approximately 4% OF the bit axial force at peak 231 b.Transient axial bending moment at peak 241 b is approximately 14%.

FIGS. 22A-22D also show that when all cutters are engaged with a uniformformation, either formation layer (see sections 204 b, 213 b, 233 b, 243b) or formation layer 42 (see sections 208 b, 216 b, 236 b, 246 b), thelateral imbalance force, the radial imbalance force, the drag imbalanceforce and the axial bending moment are all well balanced showing thatdrill bit 100 is level five force balanced. This type of “level five”force balancing is the same as traditional “one level” force balancingused in the design of prior downhole drill tools.

FIGS. 22A-22D also show that when all cutters are engaged with anon-uniform formation, from formation layer 41 to formation layer 42where some of the cutting elements are in formation layer 42 and some ofthe cutting elements are in formation layer 41, the lateral imbalanceforce, the radial imbalance force, the drag imbalance force and theaxial bending moment are all well balanced showing that drill bit 100 islevel five force balanced. For example, between section 213 b andsection 216 b of FIG. 22B, some of the cutting elements are in formationlayer 42 and some of the cutting elements are in formation layer 41, thedrag imbalance force of bit 100 is about 2.2% of the bit axial force.This type of “level five” force balancing is different from traditional“one level” force balancing used in the design of prior downhole drilltools.

For some applications, calculating the phase angle represented by arrows188 a and 188 b in FIG. 21A of lateral imbalance forces acting on eachcutting element may provide substantial benefits during multilevel forcebalancing. FIG. 22E indicates that the magnitude of lateral force actingon cutter 23 (nose cutter 1 in FIG. 21B) is equal to approximately 2.4%of total bit axial force. As previously noted, bit axial force may oftenbe considered approximately equal to weight on bit (WOB). The value ofbit axial force is approximately 15,767 pounds. Therefore, the lateralforce acting on cutter 23 is approximately three hundred and forty fivepounds (345 lbs). FIG. 22E shows that the magnitude of lateral forceacting on cutter 24 (nose cutter 2 in FIG. 21A) is approximately 2.28%of total bit axial force or approximately 320 pounds. From FIG. 22F, thephase angle of lateral force represented by arrow 188 b acting oncutting element 23 is approximately −83.5°. The phase angle of lateralforce represented by arrow 188 a acting on cutter 24 is approximately5.1°. Resulting lateral imbalance force associated with cutters 23 and24 may be calculated as follows:

F23 on x axis=F23 times cos)(−83.5°=40

F23 on y axis=F23 times sin)(−83.5°=351.7

F24 on x axis=F24 times cos)(95.1°=−28.4

F24 on y axis=F24 times sin)(95.1°=318.7

Resulting force or total imbalance force=square root of(F23-x+F24-x)²+(F23-y+F24-Y)²=35 lbs or 0.22% of WOB (15767 lbs).

A comparison of FIGS. 20G and 22J provides an even greater example ofthe improvement of lateral imbalance forces of greater reduction in thelateral imbalance forces associated with the four neighbor cutter groupson composite bit face profile 192 of rotary drill bit 90 a as comparedwith the substantially reduced lateral imbalance forces associated witheach four neighbor cutter group on composite bit profile 110 of rotarydrill bit 100. The information shown in FIGS. 22F-22J furtherdemonstrate the benefits of multilevel force balancing techniques toselect or layout locations for installing cutting elements on a downholedrilling tool using multilevel force balancing techniques and selectingthe first location for each cutting element proximate a nose point ornose axis of an associated composite cutting face profile.

Various cutter layout algorithms have been developed for the design ofmultilevel force balanced downhole drilling tools. One common feature ofthese algorithms is starting cutter layout from a nose point or near anose point to provide cutters in an associated nose zone arrangedpseudo-symmetrical about the nose point and most pre-defined forcebalanced cutter sets follow from the nose zone cutter layout.Pseudo-symmetrical cutter layout around a nose point or nose axis maysignificantly enhance bit lateral stability during transit formationdrilling.

A multilevel force balanced downhole drilling tool may have at least oneof the following four levels: (a) at cutter group level where imbalanceforces associated with cutters in each cutter group are balanced orminimized; (b) at two neighbor groups of cutter level where imbalanceforces associated with any two neighbor groups of cutters on compositebit face profile are balanced or minimized (level two force balanced);(c) at cutter set level where imbalance force associated with cutters ina cutter set are balanced or minimized; and (d) at all cutters levelwhere imbalance forces associated with all cutters are balanced orminimized (level five force balanced).

For some downhole drilling tools an additional level of force balancingmay exist (level four force balanced). For example, for a bit with 8blades using pair cutter groups, imbalance forces associated with anyfour neighbor cutters may be balanced or minimized. Another example is abit with 9 blades using three cutter groups, imbalance forces associatedwith any three neighbor cutters may be balanced or minimized. FIG. 26lists level four force balanced cutter set for given number of blades.Downhole drilling tools with level four force balanced are expected tobe more stable even if one or more cutters are damaged during drilling.

FIGS. 23A and 23B show examples of techniques or procedures which may beused to design fixed cutter rotary drill bits and other downholedrilling tools in accordance with teachings of the present disclosure tosubstantially reduce or eliminate undesired bit imbalance forces duringnon-uniform downhole drilling conditions. Method 700 may begin at step702 by inputting into a general purpose computer or special purposecomputer (not expressly shown) various characteristics of a downholedrilling tool such as rotary drill bits 90, 100, 100 a and 100 b, corebit 500 and/or reamer 600 and drilling conditions. Examples of suchdownhole drilling tool characteristics and drilling conditions are shownin Appendix A at the end of this Written Description.

At step 704 various design parameters concerning associated cuttingstructures may be inputted into the general purpose computer or specialpurpose computer. Examples of such drilling tool design parameters areshown in Appendix A.

At step 706 specific details concerning an associated bit face profileor cutting face profile may be determined including location of the nosepoint, starting radii of secondary blades from an associated rotationalaxis, location of major blades and angular position of major blades andsecondary blades relative to each other, initial layout for installingcutting elements on exterior portions of associated blades based on thenose point of the composite bit face profile or composite cutting faceprofile.

At step 708 select blade group algorithm as shown in FIGS. 25A, 25B and26. Cutter sets for use in multilevel force balancing are chosen FIGS.25A, 25B and 26 along with defining blade order for selecting locationsto installing outer cutters and inner cutters relative to an associatednose segment. At step 710 layout locations for inner cutters startingfrom the nose point based on initial composite cutting face profile andinitial blade design. At step 712 select or layout outer cutters usingpredefined cutter groups beginning with group K₀ (the initial group). Atstep 714 layout additional cutter groups (K₀+1). At step 716 useappropriate cutting face overlapping rule for neighbor cutters withineach cutter group and calculate position to install each cutter on theassociated blade.

At step 718 determine if a cutter was previously installed on the blade.If yes, evaluate overlap between cutters being considered (cutter K) andthe cutter previously installed on the blade. At step 720 compare cutteroverlaps or gaps and determine if the overlap meets design criteria forthe downhole drilling tool. If the answer is no, return to step 716. Ifthe answer is yes, go to step 722.

At step 722 determine if the last cutter in each cutter group reaches anassociate last gage cutter location on the associate gage pad. If theanswer is yes, proceed to step 724. If the answer is no, return to step714.

At step 724 layout the inner cutters using predefined cutter groupsbeginning with group K₁. At step 726 continue laying out the innercutters until the cutting elements in each inner cutter group have beendisposed on exterior portions of the associated blades. Step 728 applythe overlap rule to each cutter in the inner group. Calculate eachcutter position on the associated blade. If sufficient space is notavailable on the blade to install the desired cutter, go to the nextblade in rotation relative to the associate bit rotational axis.

At step 730 determine if the previous cutter is already on the blade. Ifyes, calculate the gap between the cutter being added and the previouscutter. At step 732 determine if the gap between the cutter being addedand the previous cutter on the blade meets the required design criteria.If the answer if no, return to step 728. If the answer is yes, proceedto step 734.

At step 734 determine if the edge of the last cutter in the cutter groupbeing considered reaches the bit rotational axis. If the answer is no,return to step 726. If the answer is yes, proceed to step 736.

At step 736 prepare a 3D visualization of the cutters disposed onexterior portions of all blades. See for example FIGS. 21A and 21B. Atstep 738 conduct a drilling simulation to estimate imbalance forcescreated by each cutter group, each neighbor cutter groups, each cutterset and each three or four neighbor cutter group on the associatedcomposite cutting face profile and all cutters. Imbalance forces may beevaluated as a function of drilling distance. See FIGS. 22A-22J.Evaluate downhole drilling performance with other criteria such as wearcurve and diamond curve. At step 740 determine if the downhole drillingtool meets desired design requirements. If the answer is no, return tostep 704. If the answer is yes, stop and use the design data that wasinput in step 702, 704 and 706 to manufacture an associated downholedrilling tool.

Table 301 in FIGS. 25A and 25B lists selected cutter sets for fixedcutter rotary drill bits and other downhole drilling tools havingbetween four blades and fifteen blades. Table 302 as shown in FIG. 26lists the preferred level four forced balance cutter sets for downholedrilling tools with five blades to fifteen blades. For a downholedrilling tool with between five blades and fifteen blades there may bemany satisfactory ways to lay out cutting elements or cutters on anassociated bit face or cutting face in accordance with teachings of thepresent disclosure.

Force Balance Procedure

In most cases, downhole drilling tools designed using procedures such asshown in FIGS. 1D and 23A-23B will satisfy requirements for multilevelforce balancing. However, if blade order is violated due to, forexample, the start radii of secondary blades, then multilevel forcebalancing may be also violated. If this situation occurs, it may becomenecessary to modify the geometry and orientation of individual cuttersor individual cutter groups. The following steps may be used:

(1) Evaluate imbalance forces contributed by each individual cutter andeach cutter group, respectively;

(2) Identify which cutter or cutter group contributes most to bitimbalance forces;

(3) Modify back rake, or side rake, or cutter size of the cutter orcutters in the cutter group;

(4) Re-run drilling simulation to see if design requirements are met ornot. If not, go back to step 1 and repeat the procedure.

If the above procedure could not balance the downhole drilling tool,then it may be necessary to re-run the computer cutter layout procedureof FIGS. 23A and 23B by changing some of the parameters used for cutterlayout, such as start radii of secondary blades, cutter layout startingpoint, cutter overlap, cutter size, back rake and side rake.

Although the present disclosure and its advantages have been describedin detail, it should be understood that various changes, substitutionsand alternations can be made herein without departing from the spiritand scope of the disclosure as defined by the following claims.

1-70. (canceled)
 71. A method of designing a downhole drilling tool,comprising: simulating drilling a wellbore using a downhole drillingtool including a rotational axis extending through a bit body and aplurality of cutting elements disposed on a plurality of blades on thebit body, the plurality of blades and the plurality of cutting elementscooperating with each other to form a cutting face profile including aplurality of neighbor cutting elements having groups of three or fourneighbor cutting elements; evaluating imbalance forces acting on eachgroup of three or four neighbor cutting elements on the cutting faceprofile; and determining locations for installing the plurality ofcutting elements on the plurality of blades based on the imbalanceforces such that each group of three or four neighbor cutting elementsare level four force balanced with respect to each other.
 72. The methodof claim 71, further comprising numbering each of the plurality ofneighbor cutting element in a cutting element set on the cutting faceprofile staring with a cutting element closest to the rotational axis asnumber one and a last cutting element located the greatest distance fromthe rotational axis as number (n), the cutting element set equal to anumber of blades on the downhole drilling tool.
 73. The method of claim72, wherein evaluating the imbalance forces acting on each group of fourneighbor cutting elements comprises: evaluating imbalance forces actingon a first group of cutting elements numbered (1, 2, 3, 4); evaluatingimbalance forces acting on a second group of cutting elements numbered(2, 3, 4, 5); and continuing to evaluate imbalance forces acting on theconsecutive groups of cutting elements until the last group (n−3, n−2,n−1, n) has been evaluated.
 74. The method of claim 72, whereinevaluating the imbalance forces acting on each group of three neighborcutting elements comprises: evaluating imbalance forces acting on afirst group of cutting elements numbered (1, 2, 3); evaluating imbalanceforces acting on a second group of cutting elements numbered (2, 3, 4);and continuing to evaluate imbalance forces acting on the consecutivegroups of cutting elements until the last group (n−2, n−1, n) has beenevaluated.
 75. The method of claim 71, further comprising: determining anose zone and an inner zone defined by respective portions of theplurality of blades; and sequentially selecting a location for eachcutting element in the inner zone at decreasing radial distances fromthe rotational axis starting from adjacent to the nose zone and endingadjacent to the rotational axis.
 76. The method of claim 71, furthercomprising: determining a nose zone and an outer zone defined byrespective portions of the plurality of blades; and sequentiallyselecting a location for each cutting element in the outer zone atincreasing radial distances from the rotational axis starting fromadjacent to the nose zone and ending adjacent to a gage pad.
 77. Themethod of claim 71, wherein: each group of four neighbor cuttingelements on the cutting face profile includes a first cutting element, asecond cutting element, a third cutting element and a fourth cuttingelement; and an angle of separation between the first and second cuttingelements is approximately equal to an angle of separation between thethird and fourth cutting elements.
 78. The method of claim 71, wherein:each group of three neighbor cutting elements on the cutting faceprofile includes a first cutting element, a second cutting element and athird cutting element; and an angle of separation between each of thefirst, second and third cutting elements is approximately equal to 120degrees.
 79. The method of claim 71, wherein at least two of theplurality of neighbor cutting elements on the cutting face profileoverlap each other by less than 100%.
 80. The method of claim 71,wherein determining locations for installing the plurality of cuttingelements on the plurality of blades comprises determining if a magnitudeof the imbalance forces associated with each group of three or fourneighbor cutting elements is less than a maximum imbalance forceassociated with each cutting element in the respective groups of threeor four neighbor cutting elements.
 81. The method of claim 71, furthercomprising selecting the locations for the plurality of cutting elementson the plurality of blades to limit transient imbalance forces duringnon-uniform downhole drilling conditions.